Musings From the Oil Patch – October 3, 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

Oil Industry Under the Gun

Before Hurricane Katrina devastated the Gulf Coast and New Orleans, the oil industry was beginning to feel the heat from consumers and politicians over gasoline prices.  Up until August 25, the date Katrina roared into Mississippi and Alabama, gasoline prices, as measured by the EIA, had climbed $0.772 per gallon, or a jump of 72.6%, since the start of the year.  The forced shut-in of oil and gas production in the Gulf of Mexico, coupled with the damage done to offshore platforms and pipelines along with refineries and natural gas producing facilities, sent petroleum prices soaring.  In addition to high prices, availability of supply has become of even greater concern.

While the oil industry was beginning to get things back under control after Katrina, along came Hurricane Rita, a Category 5 storm and at one time the third most powerful storm in U.S. recorded history.  While Rita did not deliver the knockout blow to Galveston and Houston as initially projected, it did slam into the area between the Golden Triangle of Texas (Beaumont, Orange and Port Arthur) and Lake Charles, Louisiana, doing significant damage to the refinery complex centered there.  As of Friday, September 30, almost all major refineries in Houston, Beaumont/Port Arthur and Lake Charles, accounting for 23.4% of U.S. total refining capacity, were shut down, or re-starting.  Based on the latest data, by the end of this week, all but one of the Houston-based refineries should be back in operation.  That will restore 10.8% of our refining capacity.  In addition to the Rita damaged refineries, there is slightly over 5% of our capacity still shut down due to Katrina related damage.  Gasoline prices jumped further after Rita, hitting $3.045 on September 27.  We expect the price will be lower when the government reports its industry data the middle of this week.

Gasoline availability in the Gulf region is of most immediate concern.  However, the Gulf region is a donor to other regions, so possible shortages could develop elsewhere.  The growing concern will be the impact of the refinery shutdowns on the supply of heating oil this winter, especially given the reduced supply of natural gas flowing from fields located offshore in the Gulf of Mexico.  Based on the latest data from the Minerals Management Service, 79.4% of Gulf of Mexico natural gas production is shut in (7,941.2 mmcf/d) along with 97.3% of our daily crude oil production (1,467,577 b/d).

As the impact of these two hurricanes on the oil and gas industry is assessed, commodity prices have taken another jump up in recent weeks.  The higher prices are crimping consumer pocketbooks, raising concern about the near-term health of the U.S. economy.  But now the perfect storm of tight global oil and gas supplies coupled with supply interruptions from the hurricanes has prompted American citizens and politicians to start asking why the energy industry has gotten itself, and the United States, into this condition. 

During the TV coverage of Rita’s aftermath, we saw one news anchor quizzing his station’s business reporter about the impact on the energy market, prices and consumer budgets.  He asked the question: “Why is the oil industry so concentrated in that region and why don’t they move some of their facilities?”  After we got off the floor from laughing so hard, we heard the business reporter suggesting that he didn’t think California would allow the construction of a refinery on its shores.  So true.

Today’s petroleum industry business conditions are the result of several trends – some of them beyond the control of the industry.  With respect to the location of the oil industry facilities in the Gulf Coast region, that is the historic result of where the largest oil fields in this country were found, plus the receptiveness of oil and gas producing states for these facilities.  But with respect to energy industry business conditions, the primary reason the industry is in trouble is that we have experienced an explosion in global oil consumption driven by the emergence of India and China as major economic growth engines.  Second, aging oil fields are struggling to merely maintain their current production rates, and most are beginning to slide below their recent peak levels.  Third, the conservative business philosophy of many of the oil industry leaders – somewhat conditioned by Wall Street’s demand for capital spending discipline – has made them reluctant to spend at faster rates than have been the historic norm in periods of energy crisis.  Besides, spending decisions are based on expectations about future oil and gas prices, and the past few years continue to be viewed as an aberration in long-term pricing. 

This culture of conservative re-investment by the oil industry is the outgrowth of the career experiences of today’s industry leaders.  They were survivors of the industry’s mid-1980s depression and the slow-growth environment of the 1990s that ended with another oil price crash.  As psychologists suggest, we are the product of our experiences, which explains why these managers are reluctant to invest aggressively.  To have aggressively invested in their business would have endangered their company’s continued existence.  These managers’ experiences also explain their inability to break with historic trends.  They, like many managers, are bound by human nature, causing them to extrapolate the future based on their most recent past experiences.  Thus, every oil company forecast of future oil and gas prices seems to have as its underlying assumption the reversion to the mean of today’s high commodity prices. Besides, seldom has anyone lost his/her job for being too conservative in a capital intensive commodity business.  Until Wall Street ”shoots” managers for being too conservative and under-investing, it is hard to expect that the current industry leaders are going to become the “drunken sailors” of the late 1970s!

In Business Week’s September 26 issue article, Open Season On Bid Oil, they interviewed Lord John Browne, the CEO of BP plc (BP-NYSE).  The company is already spending $14.5 billion this year on exploration and production and other capital projects.  Lord Browne told the writer, “Could we expand our investment upstream?  The answer is we have plenty of opportunities to do that.  But we can’t find the rigs, the service contracting, all the things we need to get it done.”  Unfortunately, the oilfield service industry has taken its cue regarding capital investing from its customers such as BP.  As many service company managements will discuss in private conversations, BP is an aggressive adversary in price negotiations and will start and stop operations on a moment’s notice.  (Not totally unique to BP.)  This pattern makes it difficult for service companies to invest based merely on the expectation that oil companies will continue to step up their drilling activity.  Should they stop, or cut their investing, the money oilfield service companies invested in new capital assets might earn little, or even a negative return, for the next few years – not a pleasant thought.

Besides convincing the oil industry to further step up its capital spending plans for new exploration and development, there seem to be two other issues that should be focused on.  First, the U.S. desperately needs to expand and upgrade its petroleum infrastructure, including refining, transportation and storage facilities.  This needs to involve both crude oil and natural gas.  We should consider the need to develop a strategic storage capability for gasoline, but not necessarily done by the federal government.  Certainly we will need more LNG facilities to tap the huge global gas reserves available.

The second thing we need to do is to utilize our technologies to exploit the natural resources currently available here.  These would include enhanced recovery techniques for oil and gas fields, coal-to-liquids and coal gasification technologies, deep exploration for conventional oil and gas, expansion of wind and solar power applications, greater use of nuclear power and exploring the energy potential in gas hydrates.  While this appears to be a laundry list of actions, the country needs to better diversify its energy sources to protect against adverse developments in one or more fuels holding the country’s economy hostage.

Oops!

Hurricane Rita roared through the Gulf of Mexico oil and gas producing area last week as a Category 5 storm and ultimately made landfall on the Texas-Louisiana border as a strong Category 3 storm.  During its trip, Rita wrecked havoc offshore.  All oil production and almost all natural gas production in the gulf was shut in.  A number of offshore drilling rigs were damaged and a handful of platforms were destroyed.  In its September 26 press release (Chevron Updates Activities in Gulf Region after Hurricane Rita), the company stated the following in the third paragraph.

“Initial assessments have revealed that the Typhoon tension leg platform (located in 2,000 feet of water in the Green Canyon area approximately 165 miles south-southwest of New Orleans) was severed from its mooring and suffered severe damage during the storm.  The facility has been located and is being secured.  Chevron has mobilized appropriate resources to address any environmental concerns.  No employees are at risk.”

The Typhoon platform was an engineering marvel, having come into production in July 2002, merely 18 months after partner approval of the development.  The field, located in Green Canyon Blocks 236 and 237, and located in 609 feet of water, was developed for $256 million.  The platform initially produced 40,000 b/d of oil and 60 mcf of gas, but was down to rates of half the initial production.  The field was estimated to have a life of 5-8 years.  Typhoon was owned 50/50 by Chevron (CVX-NYSE) and BHP Billiton Ltd. (BHP-NYSE).  The platform is supposed to look like the picture in Exhibit 1, but now it looks like the one in Exhibit 2.

Exhibit 1.  Typhoon Platform Design Concept

Source: Chevron

Exhibit 2.  Typhoon Platform After Hurricane Rita

Source: Resourceinvestor.com

OPEC Acknowledges Weakness in its Cartel

The actions coming out of the September 19-20 meeting of OPEC oil ministers in Vienna, Austria, confirmed our belief that a global oil industry watershed event may be underway.  OPEC announced that it was no longer going to adhere to its production quotas, but was instead going to make available to consumers all the productive capacity of its members.  OPEC is hoping that this action may help to mitigate the recent jump in global oil prices. 

Crude oil prices have been climbing throughout 2005 due to the world’s continued economic growth at a rate well in excess of forecasters’ expectations. With the recent Gulf of Mexico supply disruptions created by Hurricanes Katrina and Rita, availability of crude oil has become of greater concern within the past month driving oil prices even higher.  By sweeping aside its production quota, OPEC is admitting, at least temporarily, that it no longer will act as a cartel.

According to the online Merriam-Webster dictionary, the definition of a cartel is “a combination of independent commercial or industrial enterprises designed to limit competition or fix prices.”  Even the U.S. Energy Information Administration (EIA) has recognized OPEC as a cartel.  However, we would argue that when OPEC can no longer limit oil supplies or actually fix prices through its production policies, then it is no longer a cartel.  The interesting question is whether the cartel can reassert its market dominance in the future, or whether we are headed for some other global oil market structure?

Could the events of September 19-20 actually signal a fundamental change in the energy market?  Up until 1970, the United States, and principally Texas, maintained meaningful surplus oil productive capacity.  The Texas Railroad Commission (TRRC) was empowered with establishing the percentage of the states’ estimated peak production that would be allowed in order not to hurt prices and to conserve the natural resources of the state.  This percentage allowed was then applied to each well’s daily estimate production capability.  This became known as the “allowable.” 

The regulation of Texas oil and gas production started in 1917, some 27 years after the Railroad Commission had been created to regulate railroads, terminals and wharfs.  The first voluntary prorationing was done in 1927 for the Yates field with the blessing of the TRRC.  The first prorationing order issued by the TRRC involved the Hendricks Pool in Winkler County in 1928.  That was followed the next year with the first proration order based on market demand parameters rather than per well rates.  Early in 1930 the TRRC issued the first statewide proration order limiting Texas production to 750,000 b/d, down 50,000 b/d produced the prior year.  On October 9, 1930, the East Texas field was discovered by ‘Dad’ Joiner on Mrs. Daisy Bradford’s farm in Rusk County.  By May 1, 1931, the TRRC issued a proration order for the East Texas field (1,000 b/d) per well) at a time when the field was producing 1 million b/d, fully one-third of U.S. oil production.  The emergence of the East Texas field had dropped U.S. oil prices to $0.10 per barrel.  During the early 1930s, various legal challenges were mounted to the legality of the regulation of oil and gas production and how the prorationing was established.  By the mid 1930s, most of the legal challenges to the regulation of oil and gas production by state agencies such as the TRRC were resolved in favor of the need for states to regulate the oil and gas industry to conserve the resource. 

From the 1930s to the 1970s, new oil production outstripped consumption growth in the United States. During that time, the proration actions of the TRRC and state agencies in other states, helped to keep oil prices stable.  In the latter part of the 1960s, the production surpluses shrank as older fields depleted and newer fields failed to keep up with demand growth.  Once the allowable reached 100% in 1970, the ability of the TRRC to influence oil prices by bringing on more production ceased.  At that time, control over global oil markets and oil prices shifted from Austin, Texas, to Vienna, home of the Organization of Petroleum Exporting Countries (OPEC). 

Today, we can legitimately ask whether the power over global markets now rests in the hands of the major oil consuming countries such as the United States, China, Japan and soon India, along with the block of European countries rather than OPEC.  If OPEC cannot develop significant surplus production capacity above current and near-term consumption demands that can be brought on stream rapidly, then consumers will dictate the oil price.  As continued strong consumption growth for the past 18 months has shown and recent supply disruptions have magnified, consumers are driving pricing and not OPEC members.  Whether that changes in the future will depend a lot upon the impact of prices on consumer buying patterns and the risk of knee-jerk industry regulation.  We are looking at an interesting next six months.

One Company Steps to the Plate

In light of the heightened political attention to oil industry profits given the explosion in crude oil and product prices, it is interesting to see one company step forward with concrete actions to reinvest its money.  Anadarko Petroleum Company (APC-NYSE) announced a plan to secure the necessary drilling rigs to execute its long-term exploration and development strategy in the deep waters of the Gulf of Mexico over the next six years.  This strategy was targeted to account for roughly 23% of Anadarko’s initial capital budget for 2005. 

In 2004 following the installation of new management, Anadarko embarked on a strategy to revamp the focus of the company.  As a part of that strategy, the company sold approximately $3.5 billion (pre-tax) of non-strategic properties, retired $1.4 billion in debt and repurchased $1.5 billion in stock in a successful restructuring of its asset base.  With this new focus and the quality of the company’s remaining assets, Anadarko appears to be delivering on its long-term annual production (5%-9%) and reserve (4%-6%) growth targets.  At mid-year, in light of the strong performance of commodity prices and exploration and development trends, Anadarko added $300 million to its capital budget, increasing it to $3.1 billion – $3.3 billion, or up about 10% from last year. 

To execute its long-term deepwater strategy, Anadarko, along with two other independents, entered into a four-year with four one-year options contract for a new semi-submersible drilling rig to be built by Ensco International (ESV-NYSE).  The rig Ensco 8500 is an enhanced version of the Ensco 7500 and will be capable of drilling in 8,500 feet of water and easily upgradeable to 10,000 feet of water.  The rig will have an increased variable deck load, a two million pound derrick and increased station-keeping capability, along with numerous other improvements.  The rig is scheduled to be delivered in mid-2008 and will cost an estimated $312 million.  Anadarko has contracted for 50% of the drilling time of the original contract.

At the same time, Anadarko announced a new three-year contract with Dolphin Drilling Ltd. for use of the Belford Dolphin drillship starting in mid-2007.  Lastly, Anadarko announced it is finalizing multi-year contracts worth approximately $1.19 billion to extend the company’s existing contracts and secure incremental rigs.  It currently has two deepwater rigs under contract.

What is interesting about Anadarko’s move is that it is committing to drilling work out beyond 2010 in a world marked by increasing uncertainty.  This move speaks to Anadarko’s belief in the longevity of this industry cycle and the quality of the inventory of its drilling and development prospects.  We found comments made by James Hackett, Anadarko’s President and CEO, at the time of the contract announcement quite interesting.  He said, “Our rig-contracting efforts offer compelling economics and facilitate our deepwater drilling strategy.  In addition to addressing the cost side of the equation, we will protect our returns by hedging volumes in a manner to cover potential downside rig rates.  While we believe the dynamics of the deepwater rig market over the next six years will be very different than past cycles, we think it prudent to manage potential rig rate risk like we manage other risks – by controlling the downside and executing upon our operational strategy.”

Some Wall Street analysts have questioned why Ensco didn’t get a higher day rate for the Ensco 8500 rig.  However, they tend to ignore several features of the contract that provide attractive returns and protections for the company’s shareholders.  First, the contract is a “hell or high-water, non-cancelable” contract in keeping with management’s history of protecting its investment.  The day rate of approximately $250,000 per day compares against daily operating costs of about $55,000.  More important, there are provisions in the contract to protect the company’s profit margin.  In addition, Ensco will be paid $20 million for additional equipment upon delivery of the rig along with the mobilization cost to the first drilling location and certain start-up expenses.  Depending upon your tax rate assumption, Ensco should be able to recover 66% to 75% of the cost of the rig in the term of the first contract.     

In this day of titanic struggles between operators and service companies over pricing, we found earlier comments by Mr. Hackett enlightening.  Last November when Anadarko announced its capital budget for 2005, Hackett said, “With commodity prices substantially above mid-cycle levels, we expect F&D [Finding & Development] costs to be higher.  But more importantly, our cash margins have risen more than F&D costs, so returns have improved significantly.  We expect a reserve replacement of 150 percent to 200 percent and a reserve replacement efficiency of 1.8 to 2.2.  So, in this price environment it makes perfect sense to accelerate development projects to get volumes on-line sooner, even if these strategic decisions drive up a single-point metric such as F&D.”

We found those comments interesting in light of recent statements about contract negotiations between major oil companies and service companies made by Tom Ehret, CEO of Stolt Offshore (SOSA-OTC).  Ehret observed, “I can’t for the life of me understand why in some cases oil companies would spend months trying to mince your margin by 1% or 2%, and waste all that time, when oil prices are at 70 bucks a barrel.”  As Ehret points out, companies such as Stolt earn margins of 5%-10% when things are going well.  He believes the oil companies should be more focused on the 90%-95% of the cost of the project rather than what is generally accepted as a reasonable profit margin for the contractor.  Given oil company needs to replace, and grow, their reserve base, it would seem that the focus should be on the execution of projects.  As Ehret says, the value of six months of time saved in achieving first oil is worth a whole lot more than the totality of the profit margin they can shave by beating up on the contractors.  Amen!

Storied Penrod Rig Rejuvenated

Singapore-based Compass Energy Group, an offshore engineering firm, purchased on speculation the semi-submersible floating production unit Petrobras XXIV for use in fast-track field development and offshore accommodation projects.  The unit, to be renamed Molly Brown (for the unsinkable?) is scheduled to arrive in Singapore in mid-November.  The unit was originally built in 1975 by Marathon LeTourneau in Brownsville, Texas, as Penrod 72.  The semi-submersible rig was a Penrod-designed, six column structure that was propulsion assisted.  The rig was rated for 2,000 feet of water depth and was built at an estimated cost of $35 million.  Penrod 72 was initially part of the offshore fleet of Penrod Drilling Company, a company owned by the Hunt brothers, Nelson and Bunker. 

In 1987, Placid Oil Company, another arm of the Hunt brothers’ oil empire, converted Penrod 72 for use in the development of Placid’s Green Canyon Block 29 deepwater oil field in the Gulf of Mexico.  This was the first floating production facility in the gulf and the rig was moored in more than 1,500-feet of water.  The field, an early production success ultimately failed as production problems associated with the high wax content of the oil could not be overcome, destroying the field’s economics.  The financial failure of Green Canyon 29 contributed to the demise of the Hunt brothers’ empire. 

The Molly Brown has heated process facilities for up to 60,000 b/d, a gas export system, total power output of 8,000 kW and accommodation for 94, upgradeable to 200.  The rig does not require any major upgrades to the hull or marine systems to continue to serve as a floating production unit. 

Russia Not Out of Oil Says Putin

According to Russian President Vladimir Putin, his country is not short of oil and gas reserves.  Russia has about 72 billion barrels of oil reserves according to the latest BP Statistical Review, making it the number six country in the world behind number one Saudi Arabia’s 263 billion barrels.  In natural gas, Russia has the largest reserves at 1,700 Tcf, significantly ahead of the number two country, Iran’s 950 Tcf. 

During a three-hour televised question and answer session, Putin stated, “As for our oil and reserves, they are underestimated – there is enough for generations to come.”  That’s a good thing, since the Putin government has based its geopolitical strategy and survival on the power these reserves will give the country in an energy-tight global market.  Some analysts suggest that Russia’s oil reserves may be two or even three times the current estimate.  The problem is that Russia has not conducted serious exploration since the 1980s.  Moreover, the bulk of the yet-to-be-discovered reserves are located under the seabed or the permafrost, making exploration costly and time consuming. 

Based on certain accountings, Russia is the world’s second largest exporter of petroleum resources behind Saudi Arabia.  Russia is expected to export 5.5 million b/d this year, up from 5.14 million b/d in 2004.  The country’s target is to export 6.2 million b/d by 2010.  At the present time, virtually all the petroleum products are exported to Europe.  While this makes Russia an important player in that region, Putin’s goal is to begin exporting oil regularly by 2010 to the U.S. market that would further strengthen his political influence. 

Exhibit 3.  One Estimate of Russian Production

Source: EIA, PPHB

Exhibit 4.  Another Estimate; Same Result

Source: IEA, PPHB

Both of these estimates of Russian oil production show the same trend, although the rates of decline are slightly different.

The problem Russia has encountered is that its crude oil production growth has slowed significantly since 2004.  Many explanations for this slowing have been offered including pipeline bottlenecks, high taxes and the investment fallout from the political uncertainty created by Moscow’s restructuring of its newly privatized energy industry. 

Others have speculated that inefficiencies in the operation of the Russian oil companies have contributed to this decline in production growth.  We laughed, however, when we saw one Gazprom official dismiss this inefficiency argument by stating that they were going to offer their employees stock options and that would solve the problem.  We wonder whether Russian workers are highly motivated by potential stock price appreciation. 

Only a few people have postulated that Russia’s production problems are related to its past production policies and that the damage caused by these policies may have doomed a significant portion of the country’s reserves.  The operation of the Russian economy during the Communist era needs to be considered.  In a centrally planned economy, bureaucrats established production goals for operators and award the necessary funds and materials in order to achieve them. 

In the oil and gas business, the goal was building reserves and maximizing production.  Therefore money and critical materials such as steel were made available for exploration drilling and initial well completions.  Unfortunately, there was little money allotted for production maintenance since sustained production was not part of the plan.  Thus, operators in the field worked hard to drill new wells and bring them on production at their maximum flow rate, but then these operators moved on to their next well, paying little attention to how best to maximize the well’s, or the field’s, long-term production.  The government was interested in maximizing near-term production and not necessarily maximizing ultimate reservoir recovery.

In a recent New York Times article on the challenges to increasing Russian oil production, field operators discussed the actions they took to help expand one field’s production by 14%.  They changed out pumps and compressors, installed new flowlines and fine tuned well completions, but eventually these techniques failed to yield production increases.  The problem for Russia is to understand how much of the easy production increase has been completed.  Without addressing the problems of producing reservoirs, the fine tuning of wells and fields will yield only minor increases. 

We found it interesting that one explanation for the sharp decline in oil production growth given by an official of Rosneft, one of Russia’s largest oil companies, was that one of their newly acquired fields had been damaged in production and they had to bring down its producing rate in order to try to repair it.  That sounds like they may have a reservoir problem, which might, or might not, be solved by re-engineering the field.  Only time will tell.

Besides production problems, Russia has a tax policy issue that is impacting the health of its petroleum industry.  The Russian oil tax structure consists primarily of export tariffs and severance taxes.  The problem is that severance taxes are tied to world oil prices for determining the amount of tax owed to the government.  As a result, producers work to export the oil to earn the maximum revenue to offset the high tax.  Government officials have started a review of oil industry taxes with the goal of reshaping them so that exporting oil should not be more profitable than refining oil for domestic markets.  That is not the case now.  This pricing issue is being highlighted further by the recent decision of local oil companies to cap oil prices through the end of 2005 in the face of climbing global oil prices.

Several weeks ago, Deputy Economy Minister Andrei Sharonovsaid projected to parliament members that Russia’s 2006-2008 oil production would not grow more than 2% and oil exports by more than 3%.  He said that these growth rates would restrict Russia’s economy from expanding more than 5%-6%.  Sharonovsaid stated that Russia must modernize its existing oil extraction capacity to boost its oil production growth rate above his projection.  How and when that happens will have a significant impact on world energy markets and global oil and gas prices.

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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.