Musings From the Oil Patch – October 31, 2006

• A Refreshing Pause Or Something More Ominous?
• Everyone is Worried about Electricity
• China Filling its New Strategic Storage Tanks
• Shell Canada: Start of a Trend or a One-off Deal?
• A Boost for the Renewable Natural Gas Industry
• UK a Permanent Net Oil Importer Starting Next Year?
• FERC Rule on Pipeline ROE Scares Industry

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

A Refreshing Pause Or Something More Ominous?

 

The U.S. land rig count has stopped climbing; recently it has actually declined.  Does the flattening in the five-year advance in drilling activity reflect merely a pause that will refresh the industry, or does it reflect a more ominous scenario?  Producers have been worried about the declining trend in natural gas prices this year as gas supply growth has arrived just when demand has softened due to the absence of a cold winter and only moderate summer heat in the Midwest and Northeast regions of the country. 

 

The land rig count started this year at 1,384 with the near-month natural gas futures price at $9.63 per Mcf.  As the rig count climbed by 20% to 1,664 rigs, reached during the week of September 22, natural gas prices had dropped by more than 50% to $4.63.  Producers were becoming quite concerned about the trend in gas prices and several producers announced they were shutting in gas production that had not already been hedged earlier at substantially higher prices.  As gas prices fell, producers began slowing their drilling and well completion activity that was reflected after an appropriate lag in the rig count that has declined roughly two percent from its peak.

 

Natural gas prices have strengthened in the last couple of weeks as we have come out of the “shoulder season” marked by weak demand due to moderate weather.  The early snow storm in upstate New York and cool weather across the Northeast region, coupled with snow in the Rockies, have awakened commodity traders to the fact that once again we will have a winter this year.  The new troubling development was the release of the early estimate of third quarter 2006 U.S. GDP.  The estimate was for 1.6% annual growth in the quarter, well below the consensus expectation of 2.2%.  If this early estimate holds through the various revisions, people will have to wonder about the impact of weak economic activity on energy demand, and importantly if this weak economy lasts into 2007. 

 

Exhibit 1.  Oilfield Activity Has Paused

Source: Baker Hughes, EIA, PPHB

 

Weak commodity prices and flattening oilfield activity may be eroding oil service company pricing power.  Chesapeake Energy Corp. (CHK-NYSE), in its quarterly earnings conference call with analysts, discussed a letter it had sent to over 4,000 oil service providers indicating that the company would no longer pay for fuel surcharges and was requesting consideration of a cost rollback of 10% to 20%.  The company noted that the reception to its requests has been varied, but clearly the pressure on service companies to stop and/or rollback price increases is building.  As that works through the system, the current fat profit margins of the oilfield service companies will be trimmed. 

 

On its earnings conference call last week, Nabors Industries (NBR-NYSE) talked about the flattening in the expansion of its rig margins.  More importantly, management pointed out that it did not anticipate rig margins improving anytime soon, but rather it would mostly boost domestic earnings from additional rigs working with a little help from the rollover of lower-priced rigs to higher rate contracts, but this pricing leverage was quite small and would not drive overall rig pricing and/or earnings materially. 

 

For oilfield service companies, the pause in oilfield activity has been greeted with relief since it has eased the pressure on them to secure and train additional workers and sustain equipment utilization at peak levels.  For producers, the pause is giving them the confidence to push back on oilfield service cost pressures.  Even though gas prices have recently recovered, overall oilfield activity will likely suffer more as we head to toward year end due to the regional restrictions on winter drilling in the Rockies.  The industry pause will further embolden producers to try to push down service costs.  The biggest question will be economic activity in 2007 and its impact on energy demand and commodity prices.  Will we have a real winter or not?   Without one, gas prices will come under intense downward pressure next year as supply continues to increase and demand remains weak.  Oilfield service costs will be pressured along with equipment utilization that could signal we have seen a near-term peak in service company profit margins.  Can oilfield service stock prices go up in the face of a potential peak in profit margins?

 

Everyone is Worried about Electricity

 

The recent slump in oil and gas prices gave consumer budgets some relief.  Wall Street was immediately trying to figure out where they were going to spend this newfound windfall from lower gasoline and home heating oil prices.  Wall Street was even talking about the rollbacks in electricity rates by generators who had been granted rate hikes earlier in the year to help cover exploding fuel costs.  But what hasn’t received a lot of attention is the crying need for huge investments in additional generating and transmission capacity to assure adequate electric power in the future.  What is equally surprising is that this is not a U.S.-only issue, but Europe and Russia are also facing significant power capacity challenges.

 

In 2005 and early 2006, the margin between electricity supply and demand in Europe fell to the lowest-ever figure of 4.8%, a full percentage point below the 5.8% margin experienced in 2004.  The margin decline was driven by extreme heat in the summer of 2005 and severe cold snaps during the winter of 2005-2006 and low rainfall in Spain and France hurting their hydroelectric generating industry.  The European country with the greatest challenge is Spain.  Real capacity margins decreased to -4%, despite an increase in generation capacity of 8%.  The UK and Ireland have successfully invested in new generation capacity that has improved their margin. 

 

In the UK, the government is trying to develop a plan for future electricity generation since the country will soon face having to shut down most of its existing nuclear power plants and replacing them with coal- and gas-fired plants.  These hydrocarbon-based power generation plants will further hurt the UK’s effort to meet its Kyoto greenhouse gas emission reduction targets.  In July, the UK government floated its energy plan that would ease the regulatory regime for construction of new nuclear power plants plus supports the retention of some of the 23 existing plants that currently supply 20% of the country’s electricity.  The greatest shortcoming of the plan is that it does not provide financial assistance for construction of new nuclear plants.  It is estimated that each megawatt of nuclear power capacity will cost about $3,600 to build.  Assuming a 10% cost of capital and a 25-year payback period, the capital-cost per kilowatt-hour is about $0.05, which exceeds the cost of electricity generated by either coal- or gas-fired plants.  There is still time for Britain to adjust its power plan, but without an adjustment, either the country will struggle to meet its future electricity needs or it can kiss goodbye any chance of meeting its Kyoto emission targets. 

 

This summer in the United States, power blackouts occurred in several cities due largely to the failure of utilities to adequately invest in transmission facilities.  The most notable blackouts were in the Queens section of New York City and in St. Louis.  Both blackouts were attributed to past investment failures, but fortunately, neither of them created the extensive area-wide blackouts such as experienced by the 50 million people in the Northeast and eastern Canada in 2003.  After that blackout, a joint American-Canadian taskforce delivered a scathing report on the operational failures of the utilities that led to the power outage. 

 

The North American Electric Reliability Council (NERC), a nationwide industry self-regulatory body established in 1965 following the 1964 great Northeast blackout, recently published its annual report on the adequacy of the country’s electric power supply.  NERC has assumed new powers under the 2005 Energy Policy Act giving its report greater stature.  According to the report, the power that could be generated or transmitted would drop below the minimum regional target levels meant to ensure reliability on peak days in Texas, New England, the Mid-Atlantic region and the Midwest during the next two to three years.  Other portions of the Northeastern U.S., Southwest and Western U.S. will reach minimum levels later in the 10-year period.  The gloomy report continues the long history of gloomy power reports issued by NERC, but this report is the first to be officially filed with federal agencies and to recommend specific action. 

 

The report recommends that utilities should be encouraged to pursue financial incentives for customers to cut use during peak hours, thereby lowering demand for new power plants and transmission lines.  The financial incentives could reward customers for installing more efficient equipment or, more drastically, reward a factory for closing on a day when electricity supplies are expected to be tight.  According to the report, direct control load management and interruptible demand programs represent about 2.5% of summer peak demand (20,000 MW) in the U.S. and about 2.5% of winter peak demand (2,500 MW) in Canada.  New or expanded demand response programs and initiatives could further reduce peak demands.

 

NERC is predicting that electric power demand will increase over the next 10 years by 19% (141,000 MW) in the United States and by 13%  (9,500 MW) in Canada, but projected resources would increase by only 6% (57,000 MW) in the U.S. and by 9%  (9,000 MW) in Canada.  Utility executives are concerned about running out of generation capacity and believe that the public is unaware of how close parts of the country are to running out of power.  However, some industry executives urge caution about embarking on a massive building effort.  Peggy Fowler, CEO of Portland General Electric (POR-NYSE) said, “We all say we need energy.  But in the past, we have been terrible as an industry at predicting how much.”  She points out that past forecasting mistakes contributed to the economic problems the industry has struggled with over the past few years.  Decisions made today about building new generating capacity carry implications for customers 50, and maybe 100 years in the future.

 

Amory Lovins, head of the Rocky Mountain Institute, says, “Utility executives are talking too much to each other and not paying attention to what is going on in the world market.”  He points to the growing share of the world’s electricity demand met by co-generation plants that produce electricity and hot water or steam, distributed generation, wind, photovoltaics and biomass.  This “micropower”, as Lovins calls it, is meeting more than half of Denmark’s power needs and close to 40% of the requirements of Finland and the Netherlands.  California and a few other states are aggressively pursuing energy efficiency, load-management and new technologies, but they are way ahead of the rest of the industry.

 

Michael Chesser, CEO of Great Plains Energy (GXP-NYSE) in Kansas City, Missouri said, “The least appreciated opportunity is energy efficiency and demand management.  For the 2010 to 2015 time frame, it’s going to be the most cost-effective, least-risky investment we can make.”  He related details about the study he ordered of the company’s headquarters, a 1970s-era leased office building.  The cost of upgrading the energy-management system, air conditioning and lighting was about 70% of what it would cost to build enough generating capacity to create the amount of electricity saved by the upgrades.  Chesser went on to say that the biggest challenge is the regulatory model, or figuring out how to be compensated for the investment in efficiency. 

 

Given the growing culture in the United States demanding solutions to the country’s energy and environmental challenges, figuring out a solution to reward energy efficiency investment will be found.  In the 1970s, following the huge jump in crude oil prices, all forms of energy efficiency investments and improvements evolved.  Today, we have embraced a life-style that demands the luxury of power-hungry appliances and devices.  For example, the instant-on convenience of computers and televisions boosts our ongoing electricity needs.  For example, a plasma TV uses five times as much power as a regular TV, which is the equivalent of having an extra refrigerator in your house.  Energy demand growth assumptions are the weak link in the high energy price scenario.  More importantly, it is the one variable taken as a given – often a fatal forecasting error.

 

China Filling its New Strategic Storage Tanks

 

Xu Dingming, vice director of the State Energy Office under the State Council, recently said that the government has started filling its new strategic oil storage tanks in Zhejiang province in eastern China.  Construction of these tanks by China Petroleum & Chemical Corp., or Sinopec Group (SNP-NYSE), started nearly three years ago and finished two months ahead of schedule on September 20, according to local media reports.  The facility has a storage capacity of 5.2 million cubic meters, or 32.71 million barrels of crude oil.  This would represent about 4-5 days of current demand.

 

According to Dow Jones, Xu Dingming indicated that local oil production was being used to fill the storage tanks, although other reports are that China may be using some Russian oil or Sudanese oil.  If the country is using its own production, it would not have an immediate or significant impact on China’s oil import volume since it represents only about 90,000 barrels per day (b/d).  However, it will only be a matter of time before imports must rise to offset the loss of that domestic oil to storage. 

 

In this initial stage, China is building additional oil storage facilities at Qingdao in Shandong province and Dalian in Liaoning province as well as at Zhenhai and Zhoushan in East China.  With these additional facilities, China’s oil storage capacity will rise to 16 million cubic meters, or slightly over 100 million barrels, or 12-15 days of demand.  The tanks at Zhoushan should be ready to receive crude oil by the end of this year, while the other tanks will be ready in 2007.  China plans a second and third phase of storage facilities construction in order to amass additional crude oil and refined product supplies in order to keep pace with the country’s growing demand. 

 

In addition to its strategic crude oil storage facilities, China had about 73.3 million barrels of oil products in commercial storage at the end of last year, or the equivalent of about 21 days worth of supply based on the country’s consumption rate in 2005. 

 

China’s oil consumption continues to run at a high rate due to the sustained high economic growth the country is experiencing.  The latest economic numbers from the China Statistics Bureau suggest the country’s economy grew at a 10.4% rate in the third quarter.  This was a slower growth rate than the 11.3% rate reported for the second quarter and suggests that governmental efforts to slow the economy are working and a soft landing may be in progress. 

 

For the first nine months of 2006, China’s economy expanded at a 10.7% rate compared to the same period last year.  Industrial production during the period was up 16.1% over last year and retail sales increased by 13.9%. 

 

Spending on crude oil and natural gas production increased 19.3% for the first nine months of 2006 over 2005.  Investment in coal mines was up 36.4% in the period.  Net crude oil and refined product import volumes in September grew by 32.1% over last year and by 18.8% over the prior month to 3.9 million b/d.  Crude oil imports were 3.3 million b/d, rising by 24% over September 2005 and 2.4% above the prior record in January.

 

As shown in Exhibit 2, the monthly volume of crude oil and refined products imported by China continues to increase.  Particularly noticeable is the growth in refined product imports suggesting that the country is short of domestic refining capacity, something that it is in the process of remedying through construction of new refineries.

 

Exhibit 2.  Refined Products Imports Growing

Source: CSA

 

The greatest challenge for observers of the petroleum industry is to understand China’s oil demand and its impact on global oil markets.  China does not release inventory data.  International observers can either measure China’s apparent oil demand based on refinery throughput or crude oil production plus net imports.  Both methods yield an incomplete picture.  The throughput-based approached (used by the International Energy Agency) misses small refiners that don’t report production numbers.  The net import-based approach doesn’t account for corporate or government inventories.  The two methods vary in their month-to-month demand estimates, but typically these differences smooth out over time as inventories get pushed into the system.  Over the first eight months of 2006, the net import approach shows apparent demand growth of 10.3% while the throughput approach shows only 7.3% growth.  The difference between the two estimates is roughly 450,000 b/d, which is equal to the total production capacity of Yemen, Sudan or Prudhoe Bay in Alaska.

 

Due to this inventory uncertainty, forecasts of demand growth vary widely.  For example, the estimates for China’s oil demand growth for 2006 range from 5% to 9%.  Interestingly, the growth estimates by western government agencies tend to be at the lower end of the range (EIA at 6.7% and IEA at 6.5%) while Chinese analysts are at the high end.  The trend in global oil prices as well as Chinese government petroleum pricing and economic actions will impact demand for the balance of 2006.  

 

Exhibit 3.  China 2006 Demand Forecasts Vary Widely

Source: CSA, PPHB

 

Shell Canada: Start of a Trend or a One-off Deal?

 

On Monday, October 23, Royal Dutch Shell (RDSA-NYSE) announced that it had advised the board of directors of Shell Canada Limited (SHC-TSE) that it is intending to offer to buy the minority interests in the company it doesn’t own for a cash price of C$40 per share, a 22% premium over the closing stock price on the previous Friday.  Does the rationale for this deal reflect the start of a consolidation trend within the energy industry or merely a one-off transaction for Shell?  Either answer presents interesting implications for the oil industry.

 

Royal Dutch Shell recently has gone through possibly the most challenging period in its corporate history over the past three years as a massive reserve write-down in 2004 due to questionable management of the company’s E&P operations was followed by poor exploration success in 2005.  The result of these developments is that new management is now running the company; its former dual, nationalistic corporate structure has been jettisoned; and the company has become more aggressive in responding to changing industry conditions.  These changes have not yet produced a significantly modified corporate business plan, but possibly the bid to buy the remainder of Shell Canada is a first step. 

 

As the third largest independent oil company in terms of reserves behind ExxonMobil (XOM-NYSE) and BP (BP-NYSE), Royal Dutch Shell has struggled to recover from its reserve debacle.  Moreover, the company has been hit by production challenges in certain parts of its global operations, most particularly in Nigeria.  The company is also caught up in a struggle to bring into production its massive oil and gas project on Sakhalin Island off the Pacific coast of Russia where costs have doubled and the government is challenging both the cost estimate and the environmental performance of the project. 

 

Shell Canada is one of the largest owners of oil sands fields in northern Canada, a region attracting significant attention from both investors and industry players.  Extracting oil from these unconventional fields requires a mining processing.  However, going forward, there are likely to be more and more unconventional resource developments around the globe.  Technical expertise and financial resources become increasingly more important in the development of these types of new oil and gas fields, something Royal Dutch Shell possesses.

 

Since the oil sands developments require significant infrastructure and employ mining-type operations, they are high cost projects.  Their commercial success is partially attributable to the rise in global oil prices that has more than offset the increases in construction and operating costs of these mining projects.  For Royal Dutch Shell, securing complete control of these resources would improve the company’s reserve picture and, eventually improve its financial outlook.  Profitability would be further enhanced by organizational changes that could be made with the combination of the two organizations. 

 

While it is clear that the successful acquisition of the minority interest in Shell Canada would improve the results of Royal Dutch Shell, an interesting question is whether this move is at the forefront of an emerging industry consolidation phase.  If the major independent oil companies are stymied in their efforts to grow as a result of substantial global resource opportunities being off-limits due to state ownership and with numerous other governmental regimes being unfriendly, then acquiring undervalued companies that hold portfolios of exploration and development opportunities becomes an attractive option.  Shell Canada certainly fits in that category. 

 

The last time Royal Dutch Shell tried to buy one of its daughter companies was in 1986 when it launched an effort to buy the remaining shares in Shell U.S. it did not own.  It offered $52 per share, but the advisor to the minority shareholders, Goldman Sachs (GS-NYSE), argued that the offer was too low.  Royal Dutch Shell upped the offer to $55 plus accumulated interest on the premium.  Goldman Sachs elected to sue in the Delaware Chancery court, which yielded an additional $3 plus interest.  The final 2-3% of shareholders who held out eventually were rewarded with and additional $4 per share plus interest.  Since Shell Canada’s stock price is above the Royal Dutch Shell offer, people may be looking at the past, which raises the question of how high it will go to win?

 

People who believe this latter scenario is driving the Royal Dutch Shell move expect that the company would next move to try to buy out Shell Canada’s partners in its oil sands projects, including Western Oil Sands (WTO-TSE) and possibly Chevron Canada.  These acquisition moves would appear to be quite logical given the consolidation efforts that have gone on in the oil sands region over the past two years. 

 

Starting in the spring of 2005, Petro-Canada (PCZ-NYSE) acquired a 60% interest in the Fort Hills oil sands project from UTS Energy Corp. (UTS-TSE). That deal was followed by two separate transactions involving Chinese state-owned oil companies acquiring minority stakes in oil sands projects.  In August 2005, Total S.A. (TOT-NYSE) bought out Canadian oil sands developer Deer Creek Energy Ltd.

 

Earlier this year, Korea’s state-owned Korean National Oil Corp. acquired an undeveloped oil sands lease from Newmont Mining Corp. (NEM-NYSE) and Royal Dutch Shell acquired BlackRock Ventures Inc.  In addition, Shell Canada, Chevron Canada and Husky Energy Inc, (HSE-TSE) all secured undeveloped oil sands leases from the Alberta government.  Given this pattern of oil sands consolidations, it would not be surprising to see the Shell Canada transaction start another string of deals.

 

More important, however, is the issue of whether this deal sets off a general producer consolidation wave with major Independent Oil Companies (“IOC’s”) buying large independents such as Anadarko Petroleum (APC-NYSE), Apache Corp. (APA-NYSE) and Devon Energy (DVN-NYSE) for example, all of which possess substantial production, reserves and resource potential.  That would help the IOC’s in their efforts to sustain their production profiles and, given the large share repurchases they have been undertaking, enable them to grow their per-share reserve and production measures, which influence stock market valuations.  The downside to entering a producer consolidation phase is that the uncertainty caused by the deals often results in a slowdown in oilfield activity, not a good development for oilfield service companies.

 

A Boost for the Renewable Natural Gas Industry

 

Cargill, Inc., the farm-commodity processing giant, is embarking on a venture to turn livestock manure into methane gas.  This should provide a boost to the fledgling renewable natural gas industry.  Cargill is joining with Environmental Power Corporation (EPG-AMEX), a leader in the renewable biofuels industry, in a strategic alliance involving Environmental Power’s Microgy Inc. subsidiary. 

 

Microgy builds, owns and manages facilities that produce renewable natural gas or other energy from food and animal waste.  The company holds an exclusive license in North America for the development and deployment of a proprietary anaerobic digestion technology, which transforms manure and food industry waste into methane-rich biogas that can be used to generate electricity or thermal energy, or refined to pipeline-grade methane for sale as a commodity.  This biogas can earn greenhouse gas production offset credits that could be traded on international carbon credit exchanges.

 

Cargill has agreed to recruit farmers whose livestock operations are large enough to generate a reliable supply of manure for the anaerobic digesters that Environmental Power will build.  A digester uses microorganisms to convert manure from about 1,000 cows into methane.  A digester can cost about $1 million to construct.

 

Microgy is currently building a multi-digester biogas production and gas conditioning facility near Stephenville, Texas that will be known as the Huckabay Ridge facility.  The project will entail the construction of eight 916,000-gallon digesters, sufficient to process the manure from up to 10,000 cows.  The facility will produce an aggregate of one billion cubic feet of biogas per year with an energy content of 650,000 million BTU (equivalent to roughly 12,700 gallons per day of heating oil).  The biogas will be treated and compressed to produce and deliver pipeline-grade methane that will be sold as a commodity directly to a nearby natural gas pipeline.  The Huckabay Ridge facility will be located adjacent to a composting site that receives manure from over 20,000 cows.  The facility is the largest of its type in the world.

 

The U.S. livestock industry is struggling with new regulations dealing with the treatment of farm animal waste.  There are over 1,200 large animal feeding operations in the country that now are facing a growing number of proposed and adopted mandates from federal, state and local authorities aimed at regulating this farm waste.  These rules are placing potentially significant cost and operational burdens on the feeding operations, and this biogas technology offers a possible solution.  The farmers aren’t paid for the manure they deliver to the plant, but they may share in the profits of the venture if revenues reach or exceed a certain level. 

 

Several years ago we wrote in a Musings about the potential energy that could come from harnessing the flatulence of farm animals.  And in our last issue we discussed how the disruptive technology of the internal combustion engine eliminated the need for urban horses and mules as power sources and solved the growing animal waste problem engulfing American cities at the turn of the 19th Century.  As the old saying goes: What goes around comes around.  Maybe we are witnessing the birth of a new renewable fuel supply that will reduce our future hydrocarbon demand while solving the animal waste problem for farmers. 

 

Currently, Microgy operates three digesters in Wisconsin and is building the Texas facility.  With the support of Cargill, maybe they can build a digester for each of the 1,200 large animal feeding operations in the country.  How much of an impact on hydrocarbon demand could that mean?  In 2000, the United States consumed 6.7 billion gallons of heating oil, or the equivalent of 18.4 million gallons

 

per day.  If all 1,200 large animal feeding operations produced the equivalent output of the Huckabay Ridge facility, then the country would be generating approximately 15.2 million gallons of heating oil per day, or almost 83% of historical heating oil consumption.  Alone, this would not significantly alter our energy consumption pattern, but as a step toward reducing our dependence on hydrocarbon fuel, it would be a meaningful step down that path.  So, who from the oil patch will be the first to wade into this alternative energy industry?

 

UK a Permanent Net Oil Importer Starting Next Year?

 

The UK-based Oil Depletion Analysis Centre (ODAC) is projecting that the country will become a permanent net importer of crude oil and refined products in 2007, some three years earlier than the UK government’s Department of Trade and Industry (DTI) estimates.  According to the ODAC, and confirmed by industry analysts, the depletion rate of the UK’s oil and gas reserves in the North Sea is occurring at a faster rate than originally anticipated.  This faster depletion rate may be one of the best kept industry secrets, and one with significantly devastating implications.  Production from new North Sea fields scheduled to come on-stream over the next several years will be insufficient to offset the current steep depletion rate.

 

The DTI September monthly report about oil production and consumption shows that total indigenous UK production of crude oil and NGL’s in the second quarter of 2006 was 13.2% below the year ago quarter.  Two new fields started production during the past year, but they were unable to make up for the general production decline from older established fields.

 

According to DTI statistics, the UK was a net oil importer of 1.6 million tons (11.7 million barrels) in the second quarter of 2006 compared with being a net oil exporter by 1.1 million tons (8.1 million barrels) in the same period last year.  The UK’s North Sea oil production reached its lowest level in 16 years due to a fire at the Schiehallion oil field in August that knocked out 120,000 b/d for most of the month along with several other production related issues.  The DTI still expects the UK to return to being a net oil exporter in 2007 before becoming a permanent net importer in 2010.  The DTI believes the start-up of the Buzzard Field should offset any losses from declining North Sea oil output from older fields between 2007 and 2010.

 

The Buzzard Field, found in June 2001, is estimated to contain 400 million barrels of oil equivalent reserves and represents the largest oil field discovered in the North Sea in the past decade.  It is scheduled to begin production in December and eventually reach peak production of 180,000-190,000 b/d in 2007.  This is certainly a healthy volume of new oil supply and will impact the UK market.

 

However, we are puzzled by the DTI view that the Buzzard Field will sustain the UK’s oil production at current levels.  According to their own data, the oil depletion rate for the UK North Sea has been averaging over 200,000 b/d for each of the past three years.  That far exceeds the peak production planned for the Buzzard Field.  Now it is possible that other fields may be able to boost their production, but on the face of it, depletion will outweigh new production.  Maybe the DTI assumes that the people listening to and/or reading their statements will not go and examine the underlying data.  What was it that Lincoln said about fooling the people? 

 

Exhibit 4.  Depletion The Best Kept Secret

Source: DTI, PPHB

 

FERC Rule on Pipeline ROE Scares Industry

 

In our September 19, 2006, issue of Musings, we discussed the determination by a Federal Energy Regulatory Commission’s (FERC) administrative law judge (ALJ) that the “just and reasonable” rate of return on equity (ROE) for the Kern River pipeline project was 9.34%.  Kern River had requested an increase in its guaranteed ROE from its current 13.25% to 15.1%.  The ALJ’s rate determination was well below the 12-14% rate FERC has authorized in most pipeline projects during the past 30 years.  As we discussed then, the gas pipeline industry was concerned that the low ROE rate could chill investor interest in pipeline investments hurting the industry’s ability to grow.

 

The Interstate Natural Gas Association of America (INGAA) commissioned a white paper to examine why FERC arrived at this low of a rate.  It appears that when FERC is using its discounted cash flow analysis, it adds the dividend yield rate for a series of proxy companies to a projected rate of growth in earnings per share for each company.  FERC then typically establishes its target ROE at the median for the range of the proxy companies.  The INGAA white paper found that the selection of proxy companies was skewed due to the inclusion of companies with either local distribution or exploration and production businesses.  The other companies included were more typical of pipeline companies, but two of the three companies are still recovering from their prior disastrous business expansion ventures.  The white paper argued that FERC should have included some master limited partnerships (MLPs) as proxy companies because their businesses and competitive issues are similar.

 

FERC doesn’t include natural gas MLPs in their determination because part of their return to investors is a return of capital, which it believes is not comparable to stock dividends and might skew investor expectations.  FERC recently ruled on the Kern River pipeline rate case and overturned the ALJ’s ruling that the 9.34% ROE was appropriate.  Instead, FERC ordered an 11.2% rate.  The rate was determined by taking the median ROE of the group of comparable companies and adding 0.5% to account for the risk differences between Kern River and the comparable group. 

 

The pipeline industry is upset with the FERC ruling, not just because it reduced the current Kern River ROE, but because it may impact the ability of MLPs to continue to grow their cash flows that have made their equity and debt attractive investments for investors.  The high guaranteed ROE’s of MLPs have been critical for their cash flows.  If increases in regulated rates are about to slow down, or even decline, this could have a significant impact on the ability of MLPs to attract investment and to continue to pay out substantial dividends.  The Kern River case may be the first skirmish in a war over ROE’s, but the industry doesn’t appear to have yet developed an argument for rate increases that FERC finds compelling.

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