Risk Is A Four Letter Word

- Risk Is A Four Letter Word

Thursday, August 18, 2011
Rigzone Staff
by Trey Cowan

The average investor often overlooks the simple concept of how the market discounts risk. Risk and reward typically correlate strongly with one another. Currently, the risk premium that an investor demands in exchange for lending to broader markets is expanding. In broad terms, investors must be anticipating that future risk levels are increasing.

To better define the risk/reward relationship, we first point to the current situation surrounding the 10-Year Treasury Note. From July through the week ending August 12, 2011, the note's yield has declined 26 percent from 3.18 percent to a 2.34 percent. Today, the 10-Year dropped below 2 percent.

Previously, the lowest the yield on the 10-year was 2.12 percent, set in December 2008; when fears regarding the global credit freeze were near their highest levels. Yields for fixed income instruments respond inversely to price. Investors buy the 10-Year to reallocate their holdings away from risk and into this safe-haven, which has the effect of driving the price up. We note the key concept in finance: the yield on a 10-Year is often looked upon as the proxy for the risk-free rate of return.

Another component in the valuation of assets is the risk premium. As the risk-free rate of return shrinks the average risk premium an investor demands must rise. In other words, if the 10-year yield is falling, then market risk is actually on the rise. Let's assume for a moment that an investor wants a 10 percent return on their investment. If the risk free rate has dropped from 3 percent to 2 percent, then the risk premium that investor is willing to take on has grown by a corresponding amount. Otherwise, the investor's required return falls to 9 percent (signifying their aversion to taking on additional risk). Therefore, when we see dramatic drops in the 10-year, like what just took place, all else equal, investment risks must be perceived to be on the rise. Such a move is justified to mathematically keep the overall return at equilibrium.

Using the earnings estimates we can prove that these financial concepts are factoring into current market valuations. For our example we are using the earning's yield of the the S&P 500 Index. We took the recent annual earnings for the S&P 500, $112.8, and divided it by the index value for the week ending August 12, 2011 (1178.81). What we found was that the earnings-to-price (E/P) yield was 9.5 percent. If you subtract the corresponding 10-year treasury yield (i.e. the risk-free rate) of 2.3 percent from the E/P, the remainder is the risk premium for the S&P 500 Index (i.e. 7.2 percent).

The risk premium for the S&P 500 is relevant for two issues. First, the S&P 500 includes only well-capitalized U.S. operated firms of a significant size. If the market expects a total earnings yield of 9.5 percent for blue-chip U.S. firms, then obviously the required return (and associated risk) for lesser quality investments is going to be higher. Second, the current risk premium at 7.3 percent for the S&P 500 is well outside the norm (3.85 percent average since 2005 and 5 percent YTD).

This growing level of inherent risk in the broader markets and the market's appetite for risk does have an impact on oil prices that is worth considering. Although the Fed's posture towards interest rates (and their vow to hold them low into 2013) would suggest that the dollar will remain weak, this is no time to get bullish on oil. Look no further than price variability to understand our reasoning. Since 2005, one standard deviation in the price of a barrel of oil represents 25 percent of the total price. Conversely, one standard deviation in the S&P 500 Index approximates 15 percent of the total. Therefore, at a time when the market is risk averse, an investment in crude oil bears with it 66 percent more risk than the total market.

Suppose that inherent in recent market sentiment is a fear that the U.S. economic growth profile for next year will slip by about 10 percent or approximately three-tenths of one percent of GDP. Ultimately, such a scenario would be accompanied by less demand for oil. We used regression analysis to compute the value of one barrel of oil based on a 10 percent decline in S&P 500 earnings using observations starting in 2005. Our calculations peg the implied value of WTI crude oil at $84/barrel based on if NTM earnings estimates drop $11 for the S&P 500 Index. Our calculations would be well below what the EIA and leading economist recently had considered a reasonable assumption for next year (+$100/bbl).

Also, consider how much the current risk premium exceeds its average 52-week value. Recent history suggests that a growing risk premium (that is well outside this 52-wk norm) spells trouble for oil prices. Back in 2008, risk premium exceeded its own norm by 2 percentage points. Oil prices in the subsequent 10 weeks fell 53 percent. Again in 2010, the S&P 500 risk premium broke 2 percent above its norm and oil prices fell 5 percent in the following ten weeks. With the markets now showing a risk premium that is again 2 percent above the norm, a repeat of this pattern does not seem far-fetched.

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U.S. Faces Increased Energy Security Risk, Report Shows

- U.S. Faces Increased Energy Security Risk, Report Shows

Tuesday, August 09, 2011
Rigzone Staff
by Barbara Saunders

The U.S. faces heightened threats to its energy security, according to a new report by the U.S Chamber of Commerce that measures risk in four areas—geopolitical, economic, reliability and environmental.

For 2010, the energy security risk index score was 98.0—the fourth highest since 1970 and a 6.5 point increase from the 2009 score of 91.5.

"These are the worst risks we've seen in recent history," said Karen Harbert, president of the Chamber's Institute for 21st Century Energy. "They approach what we saw following the Iranian hostage crisis. . . . Unless we take dramatic action to change the trajectory, America is headed toward an unprecedented level of sustained risk."

The index, updated annually, tracks changes in energy security risk beginning in 1970 and projects future risk through 2035. The 2011 edition of the index incorporates the most current energy data from the U.S. Energy Information Administration (EIA) and other federal agencies.

Of the 37 metrics weighed, 20 showed increased risk in 2010, 11 showed improvement, and six were unchanged. Eight of the top 10 metric with the largest score changes related to energy prices, price volatility and expenditures, the Chamber said, adding that the index projects a sustained period of high risk all the way through 2035. "These risks would be even higher if not for improvements made in energy efficiency, and the potential for shale gas to improve the security of natural gas supplies and lower energy costs," the Chamber added.

"We must maximize all of our domestic energy resources, make clean energy technologies more affordable, and eliminate regulatory barriers that are stalling urgently needed energy projects," Harbert said. "Only by taking these actions will we reduce our energy risks and make the nation and economy more secure."

The 2011 edition includes some adjustments to the index's formula based on feedback from last year's inaugural report. Adjustments also were made to some previous year's scores based on updated data from government sources. Most significantly, the 2009 score was adjusted from 83.7 to 91.5, largely because revised data that showed resurgence in high energy prices occurring more rapidly than originally estimated.

Highlights of the report included:

• Geopolitical energy security risks rose to 97, 13.5 points above the 30-year average of 83.5. Most of the increase in risks seen in this sub-index since the early 2000s is linked to higher crude oil prices and volatility and greater import expenditures. The metrics measuring security of global fossil fuel reserves and production were essentially unchanged from 2009.
• Economic energy security risks increased by 9.3 points in 2010 to 94.0, offsetting a large portion of the 17.1 point drop experienced in 2009. "This level of risk is well above the 30-year average of 73.7 for this sub-index and has been exceeded only in 1980, 1981, and 2008," the Chamber noted.
• Reliability energy security risks increased 5.4 points to 111.0 in 2010, the highest recorded for this sub-index, with crude oil price volatility being responsible for much of the increase. The score for this sub-index has hit 100 points or more every year since 2005, and projections indicate that levels of risk above 95 will be maintained through 2035, even after assuming that crude oil energy price volatility will return to historical averages.

In one bright spot, the Chamber noted that the "potential of shale gas to improve the security of natural gas supplies and lower energy costs and expenditures is beginning to emerge. Recent estimates double the volume of recoverable shale gas resources assumed in past estimates, leading to greater domestic and global supplies and lower gas imports. Increasing shale gas supplies and further improvements in natural gas extraction technologies will further delink the prices of crude oil and natural gas."

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ConOps Service Launched to Reduce Integrated Control System Risk

- ConOps Service Launched to Reduce Integrated Control System Risk

Tuesday, July 19, 2011
Rigzone Staff

Houston-based Athens Group, a provider of risk reduction services for control systems software on high-specification offshore assets, today unveiled its new Concept of Operations (ConOps) service.

Output from this service, a ConOps document, helps reduce integrated control system-related risks, such as non-productive time (NPT), health, safety and environmental incidents, from the very beginning of newbuild and refurbishment projects.

A ConOps document, or text document, defines from the owner's perspective performance, quality, health, safety and environmental (PQHSE) expectations; validation and verification requirements by project phase; and contractual requirements for the owner to sign by project phase.

Most offshore assets are now built or refurbished through turnkey, builder furnished equipment contracts. This procurement model makes it challenging for the asset owner to exercise the level of oversight and control needed to hold their vendors accountable for delivering a safe, reliable, and fit-for-purpose asset, the company said.

In Athens Group's recent industry survey, The State of NPT on High-Specification Offshore Assets: Third Annual Benchmarking Report, 89 percent of drilling contractors and operators identified the development of a software-specific risk mitigation plan as an opportunity the reduce NPT. Implementing a ConOps phase is the critical first step in mitigating software risk throughout the offset asset life-cycle, Athens Group said in a statement.

"Many of the project delays and much of the NPT we've seen could have been prevented if risk reduction planning had started earlier in the project life-cycle," said Athens Group CEO Mike Haney, noting that other industries that rely on large, one-of-a-kind systems integration projects have significantly reduced risk by starting each project with a Concept of Operations document.

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BMT Group Appoints Risk Management Specialist

- BMT Group Appoints Risk Management Specialist

Friday, July 08, 2011
BMT Group Ltd.

BMT Group announced the appointment of Jayne Matthews as Manager, Operational Risk. Jayne will be responsible for leading and managing risk and risk support activities, as well as the internal audits of BMT Group and BMT subsidiary companies. She will also take charge of controlling BMT's unique Sustainability Management System (SuMS).

Jayne has over 20 years' experience working in quality management. She also holds a BA in Biochemistry, PHD in Biological Sciences, Post Graduate Certificate in Quality Management, membership of the Chartered Quality Institute and is a Chartered Quality Professional.

Jayne joins BMT Group having run her own management consultancy business for a number of years, specializing in the development of management systems which focused on both quality and the environment.

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Eni Takes Risk; Develops Nikaitchuq Field

- Eni Takes Risk; Develops Nikaitchuq Field

Friday, July 08, 2011
Rigzone Staff
by Jaime Kammerzell

Eni began oil production at the Nikaitchuq field in February 2011. The field is located in the Beaufort Sea off the North Slope of Alaska in 3 meters of water. It is also Eni's first operated Arctic project.

Eni owns 100% interest in the Nikaitchuq field, which is a risk for the operator. The Nikaitchuq field is a marginally economic field with cold viscous crude oil. The reservoirs are about 4,000 ft TVD with long step outs. However, Eni also reaps all the benefits of its hard work. The operator estimates recoverable reserves at 180 MMbbl and expects Nikaitchuq to produce for over 30 years with peak production of 28,000 b/d. Total investment will amount to about $1.45 billion.

Field Development

In January 2004, Kerr-McGee drilled the Nikaitchuq No. 1 vertical well, which tested more than 960 b/d of 38 degree API crude oil from the Sag River Formation. Kerr-McGee then drilled the Nikaitchuq No.2 well 9,000 ft southeast of the No.1 well in March 2004 and successfully extended the accumulation down dip.

Kerr-McGee operated the NW Milne Point field with a 70% interest in 2004. Armstrong Alaska, Inc. held the remaining 30% interest.

Nearly a year later, Kerr-McGee tested the Schrader Bluff reservoir at the Nikaitchuq No. 4 horizontal appraisal well. The well tested at rates of up to 1,200 b/d and the oil tested at 16 to 17 degrees API. Kerr-McGee estimated the discovery to hold 100-200 MMboe.

Eni, which previously bought out Armstrong Alaska's 30% interest, bought out Kerr-McGee's operatorship and 70% interest in the Nikaitchuq field in April 2007.

The development plan called for 71 wells, including oil producers, water injectors, and water source/disposal wells. Eni planned to drill one-third of the wells from shore and the remainder from an artificial island to be constructed about 2.8 mi from shore in Phase 2 of the field's development.

Field development started Jan. 25, 2008. Though the operator slowed drilling and development operations in March 2009, all wells should be completed by 2014.

Eni is drilling the Nikaitchuq wells horizontally through thin layers of oil-bearing rocks. They are at 4,000 ft VD and have a horizontal reach of up to 20,000 ft. The produced oil is viscous and thick. So to speed the flow, Eni injects water from the Ivishak formation and produced water. The Ivishak water is about 195 degrees, which when mixed with the crude (about 87 degrees) will help it move through the subsea pipeline to the processing facility quicker.

Eni contracted an offshore rig for the offshore drilling pad in 3Q 2010. The offshore wells require electric submersible pumps, which are housed on the drilling pad.

Eni designed the onshore processing plant at Oliktok Point to handle sand and water as well as crude. Two process modules built in Louisiana weigh about 4,000 tons each. They will work with 22 smaller module units, built in Alaska, to treat up to 40,000 b/d of heavy crude with sand and up to 120,000 b/d of water.

A 3.8-mile-long under seabed pipeline bundle, which is the heaviest bundle ever installed in the Arctic, connects the offshore facility to the onshore facilities. Eni contracted INTECSEA to perform the Pre-FEED, FEED, detail design and construction support on the subsea flowlines. The flow line and utility bundle connect to the onshore facility at Oliktok Point. The pipleline bundle was installed in 2008 and includes an outgoing pipe that takes water to the drilling pad, a diesel line, and cables. Hot water flows out to the drilling pad through a concrete-coated pipe.

Production flowline bundle included:

• 3 phase PIP production flow line 18-inch x 14-inch
• 12-inch water injection Flow line (2-inch insulation/1-inch concrete)
• 6-inch spare Flow line (single wall)
• 4-inch x 2-inch PIP diesel line
• Fiber optic cable with bundle
• Separate fiber optic and power cable bundle

Nikaitchuq Field

Alaskan Future

In 2008, Eni won 18 exploration leases in northern offshore Alaska in Lease Sale 193.

The blocks are in the Chukchi Sea, in 30 to 50 m of water. According to the company, this area possesses a high exploration potential recognized by several oil majors who competed for the blocks. Eni jointly owns 14 of the leases with Statoil-Hydro and wholly owns four of the leases. These leases position Eni as a major player in Alaska.

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S&P Lifts BP Outlook To Stable; Sees Less Downside Risk

- S&P Lifts BP Outlook To Stable; Sees Less Downside Risk

Wednesday, July 06, 2011
Dow Jones Newswires
by Melodie Warner

Standard & Poor's Ratings Services revised its credit outlook on BP to stable from negative, saying it sees less downside risk to the oil company's credit quality and little evidence of further erosion to its business standing.

The ratings company also affirmed BP's long-term corporate credit rating of A, which is five steps below the coveted AAA.

"The stable outlook reflects our view that BP is well positioned to meet potentially substantial additional fines and other payments related to the Gulf of Mexico disaster," the firm said. For its analysis, S&P assumes that all Gulf of Mexico-related payments will total less than $55 billion and will be spread over several years.

The ratings firm noted BP's first-quarter average realized oil price was 19.2% higher than the fourth quarter, and rose 31% from a year earlier. BP's refining margins also expanded in 2011, while its underlying downstream operating profit increased to $2.1 billion in the first quarter, from a quarterly average of $1.2 billion in 2010, despite a 6% decline in refining throughput, S&P said.

But, a sustained decline in oil prices below $70 a barrel alongside underlying operating cash flow of less than $25 billion could put downward pressure on the ratings, S&P said. Any upside rating potential is limited until there is more clarity on the penalties BP could face in the U.S. for the Gulf of Mexico oil spill.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Holistic View to Rig Design, Construction Needed to Minimize Software Risk

- Holistic View to Rig Design, Construction Needed to Minimize Software Risk

Monday, May 30, 2011
Rigzone Staff
by Karen Boman

The growing use of software to run drilling rigs, coupled with the regulatory and operational challenges of the post-Macondo world, means that drilling rig contractors should take a more holistic view to reducing control systems software and hardware integrated-related non-productive time (NPT) and schedule delays.

According to Athens Group's third annual International Benchmarking Survey, this holistic approach include designing, building and testing a drilling rig as an integrated system, rather than testing individual systems before they are put together. Athens Vice President of engineering Bill O'Grady said this would allow for software risks to be addressed earlier in a rig's lifecycle.

The fact that most drilling equipment used today is software-driven presents challenges, and delays in rig delivery and problems integrating software systems mean lost revenue and additional costs for drilling contractors. "Typically, we see a collection of equipment built and tested separately and put together late in the process," said O'Grady. The task of integrating software systems also is spread among employees, rather than one person assigned the job. "Unless these systems integrated, you won't get the benefits of the software programs."

The study focuses on the cost and causes of control systems software and hardware integration-related NPT and safety incidents, and seeks to identify opportunities and barriers to reducing NPT and was as initiatives planned for 2010 and 2011. While progress has been made in reducing software and hardware-related NPT, the study found that the rate of control system and hardware integration NPT is 67 to 86 percent higher than the acceptable rate, depending on the age of the asset.

The top causes of NPT, with the exception of lack of shipyard experience, which is now last on the list, remain the same from last year's survey. The top causes include overextended equipment vendors, lack of software-experienced engineers, and late delivery and testing of software.

Many engineers lack software experience since oil and gas industry traditionally has been a hardware intensive company with mechanical control systems on board drilling rigs. In the past decade or so, the benefits of introducing software programs to control functions on board rigs began to take hold in the industry, but engineers more familiar with hardware are still adapting to using software.

Athens CMO Christine Lowry also attributes the lack of software experience to the 1980s energy industry bust, when many workers were laid off. This bust likely scared off potential recruits who would have entered the industry in the 1990s, many of whom would be familiar with computer software.

While software systems became prevalent on drillships and semisubmersibles in 1998, so few rigs are typically delivered each year, with the exception of last year, that experience installing integrated software systems is still lagging in comparison to other industries. The year 2010 was an exception, and equipment vendors were stretched thin due to 48 high-specification rigs delivered, the largest number of deliveries ever.

Two trends O'Grady sees among rigs is that older platforms with electromechnical systems need to be completely refurbished with a software system, and rigs built in 2000 through 2004 coming in for refurbishments also require software upgrades. Rigs such as the ENSCO 8500 series are the same in theory, but because software versions change, there is not a lot of duplication.

The survey found that adoption of simulation testing for topsides, improved rig crew training, and implementation of alarm management software are the top three opportunities for reducing NPT.

Thirty-seven percent of respondents in the survey indicated they would implement improved rig crew training this year, with training needed specifically targeted at the operation of complex integrated software control systems, and the maintenance and configuration of complex integrated software control systems. Survey respondents also included the adoption of simulation testing for topsides and implementation of alarm management software in their top three NPT reduction initiatives planned for this year.

O'Grady noted that simulation can be a valuable tool to test software, but choosing the right simulation and at the right time in the product lifecycle is critical for success. "The simulator also needs to be independently verified to ensure it is testing appropriately," he noted.

Implementing alarm systems on rigs requires a different approach with high temperature, high pressure wells offshore. More alarms are needed, but alarms must be placed where they matter most. "If too many are in place, people will likely ignore them or turn them off," O'Grady said.

One recommendation made in the report is drilling contractor's use of a concept of operations document, a well-known practice in automation and manufacturing process, for the design of newbuild rigs and refurbishment of existing rigs, said O'Grady. The concept of operations document, in which the end user describes what tasks they want an asset to perform, is missing in a lot of highly integrated assets such as drilling rigs.

O'Grady also noted that rig owners are now taking more control of the commissioning phase of rigs. This approach is a shift from the original owner-furnished equipment in which a rig owner specified to a shipyard what particular pieces would go on a rig. However, the implementation of software on rigs began to cause delays with rig deliveries. Shipyards began suggesting that, while shipyards could standardize some equipment parts for rigs, more specialized pieces with software-dependent parts should be put in place by the owner.

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[Oil and Gas Post] - Oil Slips From Two-Week High on Speculation Mideast Risk Limited to Libya

Oil Slips From Two-Week High on Speculation Mideast Risk Limited to Libya

By Grant Smith and Ann Koh - Mar 22, 2011 4:22 PM GMT+0700

Crude oil retreated from its highest price in almost two weeks amid speculation that supply disruptions from political unrest in North African and the Middle East may be confined to Libya.
Futures slipped after climbing as much as 0.3 percent as demonstrators in Yemen spent the night on streets to maintain pressure on President Ali Abdullah Saleh, who is facing a growing internal revolt. Tension in the region is adding a risk premium of $15 to $20 a barrel to Brent oil prices, according to Societe Generale SA.

“The unrest in Libya seems to be priced in almost completely by now,” Eugen Weinberg, head of commodities research at Commerzbank AG in Frankfurt, said in an interview with Bloomberg television. “The price will stay at elevated levels of around $110 to $120 for several months and will drop back to $90 by the year-end.”

Crude for April delivery on the New York Mercantile Exchange was at $102.05 a barrel, down 28 cents, at 9:15 a.m. London time, after rising as high as $102.67. Yesterday, it gained $1.26 to $102.33, the highest settlement since March 10. The April contract expires today. The more-actively traded May futures were down 22 cents at $102.87 a barrel. Brent oil for May settlement was at $114.65, down 31 cents, on the ICE Futures Europe exchange in London after rising as much as 0.5 percent. The spread between the two May contracts narrowed to $11.80 a barrel from $11.87 yesterday.

Regional Unrest

Regional turmoil has toppled the leaders of Tunisia and Egypt and reached Yemen, Bahrain and Syria. Societe Generale raised its forecast for Brent by $11 to average $109 a barrel this year as political risks increased, analysts led by Michael Wittner said in a report dated yesterday.

Allied forces are expanding their air campaign over Libya in an effort to thwart Muammar Qaddafi’s fighters and enable rebels to control cities, such as the opposition capital of Benghazi, which had been under attack by troops loyal to the regime. The Libyan leader denounced the coalition allied against him, which includes the U.S., the U.K. and France, as “the party of Satan.”

Libyan output has fallen to fewer than 400,000 barrels a day, Shokri Ghanem, chairman of Libya’s National Oil Co., said on March 19. The country produced 1.59 million barrels a day in January, according to estimates compiled by Bloomberg. Exports may be halted for “many months” because of sanctions and damage to facilities, the International Energy Agency said.

Libyan oil production is likely to remain disrupted for the rest of this year, said Lawrence Eagles, head of commodities research at JPMorgan Chase & Co. in New York.

Protest in Yemen

Thousands of Yemenis spent the night on streets across the country to maintain pressure on President Ali Abdullah Saleh, who is facing a growing internal revolt by army leaders, ministers and diplomats. Yemen produced about 298,000 barrels of oil daily in 2009, according to BP Plc data.

Military officers including Ali Muhsin al-Ahmar, commander of the first armored division, and Mohammed Ali Muhssein, commander of the eastern region, abandoned the regime yesterday. Their move was a result of the crackdown three days ago that left dozens dead, said Mohammed al-Sabri, an opposition leader.

Bahrain’s government declared a three-month state of emergency on March 15 after troops from Saudi Arabia and other Arab Gulf states arrived to help in quelling more than a month of protests.

Japan is delivering more relief supplies in areas hardest hit by the March 11 earthquake as workers restored power to two reactors at a crippled Fukushima Dai-Ichi nuclear power plant yesterday, prompting Prime Minister Naoto Kan to say there was “light at the end of the tunnel.”

Short-Term Drop

“The recent tragic events in Japan will result in a sharp short-term drop in economic activity but is likely to be followed by a strong recovery driven by reconstruction and replacement of durables which would boost the demand for many commodities,” Societe Generale’s analysts said.

Japan was responsible for 5.2 percent of global oil demand in 2009, according to BP, which publishes its Statistical Review of World Energy each June. Japan is the third-biggest crude- consuming country, after the U.S. and China.

To contact the reporters on this story: Ann Koh in Singapore at akoh15@bloomberg.net; Grant Smith in London at gsmith52@bloomberg.net

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