Oil Industry Restructuring Beginning – What’s The Outcome?

PPHB-logoAn Excerpt from 'Musings from the Oil Patch'
March 10, 2015

By Allen Brooks
Managing Director, PPHB

Global crude oil prices peaked in mid-June and began drifting lower slowly but didn't drop below $100 a barrel until early/mid-August. From there, the pace of the decline began to pick up as the $80's were reached in early/mid-October and the $70's in early/mid- November. On that fateful Thanksgiving Day (a turkey of a day for oil industry participants) when Saudi Arabia officially nixed the idea of cutting its production in order to support oil prices for the rest of its fellow OPEC members and other significant oil exporters, West Texas Intermediate (WTI), America's benchmark crude oil price, sat at $73.70. Internationally, the price quoted for European Brent crude oil was $77.39 a barrel. In approximately 45 days, the Brent spot oil price shed slightly over $32, reaching a low on January 13,2015, of $45.13 a barrel. In the case of WTI, it took nearly 60 days for the price to lose slightly more than $28 a barrel, hitting its low of  $44.08 a barrel on January 28, 2015. From the peak to the recent trough, Brent has fallen by 61%, while WTI dropped 59%. Since then, the oil market has rebounded somewhat in response to slightly improved economic data for the United States, the Eurozone and Japan. China's economic results have been much more muted leaving analysts guessing how much oil it may need to import. The net result of the oil price rebound is that from the peak in mid-June to the end of February, the declines are 54% for WTI and 46% for Brent.

The recent oil price lows were set in an environment of extreme uncertainty. Would they mark absolute lows for this cycle or merely delineate temporary lows before falling further in the spring as the absence of demand coupled with unrelenting increases in supply are rapidly filling available storage facilities. Once storage tanks are full, oil prices will need to drop again in order to entice buyers, primarily refinery operators but also speculators, to step up purchases.

Instead of watching falling oil prices, oil and gas exploration and production and oilfield service company managements were aggressively cutting their capital spending plans and announcing employee layoffs. These actions were taken in an attempt to right- size the business for its anticipated level of activity. Managements were optimistic the downturn would have a "V" shape, similar to what was experienced during the 2008-2009 downturn and subsequent recovery. As time has gone on, however, that view is being dismissed as the forces behind this downturn appear to be more long-lasting and thus require additional time to correct. The duration of time required remains an elusive guesstimate.

Initially, a number of managements accepted that the downturn would be more severe than the one experienced in 2008-2009 and began preparing for an extended period of low oil prices, even though they had no idea of exactly how low prices would go or how long they would remain low. As a result, when managements began cutting spending and employees, most did so with meat-cleavers rather than scalpels. Two surveys conducted by prominent Wall Street investment banks suggested that exploration and production capital spending this year would decline significantly. The surveys were conducted by Cowen and Company and Barclays and were prepared late last fall just as the oil price collapse was becoming evident. Much like a slow-motion train wreck, companies prepared their capital budgets using assumptions of what the oil price would average in 2015 knowing that their estimates were slowly sinking. Recognizing that their oil price assumptions were just that, assumptions, they prepared budgets utilizing different, and in most cases, significantly lower oil prices. As a result, when the investment banks' surveys were announced, many observers thought they were unrealistic. However, they began focusing on the alternative spending reductions based on lower oil prices; the reality of how difficult 2015 would be for the industry became clearer.

Cowen's study forecast that global E&P capital spending would decline 17% in 2015 to $571 billion. But that projection was based on oil prices averaging $70 a barrel. Cowen reported that at a $60- a-barrel average price, spending would drop by 30-35%, or roughly twice its initial estimate. Surprisingly, the Barclays survey wound up
at about the same spending cut assuming a $50 a barrel average oil price for 2015 although the survey's initial projection called for a reduction of about half the Cowen forecast at $70-a-barrel oil pricing.

With industry spending cuts of 30-35%, activity was destined to collapse, and it has. The drilling rig count, as reported weekly by Baker Hughes (BHI-NYSE), has dropped by 664 rigs from its recent peak established the week ending September 26, 2014, to the week ending February 27, 2015, shrinking the active rig count by over
one-third. Surprisingly, during the crisis of 2008-2009, the active rig count fell by 1,155 rigs from peak to trough, a period that extended for 39 weeks. If we assume the current rig correction will match the earlier one, the industry still needs to lay down another 500 active rigs. We would like to make two points about this comparison. First, the 2008 peak had exactly 100 more active rigs than last fall's peak. Second, the current downturn from its peak has lasted 22 weeks. At the same point in the 2008 correction, only 28 more rigs had been shut down than now. So has this rig downturn been worse than 2008? It would seem to be the case until one recognizes that the prior downturn started with many more rigs and still had more active rigs at the same point where we are now in this downturn. Key questions are whether this downturn needs to last as long as the prior one did, and if the rig count needs to fall to the same level as in 2009. If it needs to last as long as 2008-2009, then the drilling industry needs to endure another four months of falling rigs. If we have to cut another 500 rigs, at threcent weekly pace of 40+ rigs per week, we are looking at only another three months. As shown in Exhibit 1, the shape and pace of the rig downturns have been very similar. If this downturn continues to follow the earlier one, then we likely have 7-8 weeks of weekly rig count declines as experienced in the past two weeks before the rate of decline slows and we reach 39 weeks of downturn duration. The good news from this analysis is that we may be nearing a bottom in the rig decline. The bad news is we don't know when or how fast the rig count might rebound.

Exhibit 1. Current Rig Downturn vs. 2008-2009 (Source: Baker Hughes, PPHB)


While the rig count is one indicator of current oil and gas industry activity, it doesn't tell much about underlying changes that may be going on in the business. Those changes only become apparent when we look back at measures of activity or results. We sense the events we are observing and the comments we are hearing mean that structural changes in the global oil and gas industry are underway. We have been ruminating about some of these observations and their potential significance. One such observation is the analysis of the history of the oil industry and its interpretation for the future suggested by iconic Boston-based money manager Jeremy Grantham of GMO.

In his firm's 2014 third quarter investor newsletter, Mr. Grantham commented on the role of energy, and especially that of coal and oil, in our economic history and our future. The article was titled, The Beginning of the End of the Fossil Fuel Revolution (From Golden Goose to Cooked Goose). Mr. Grantham is an avowed supporter of climate change research and steps to mitigate the impact. He and his wife have established a foundation to support this research. In the letter Mr. Grantham points to the need for cheaper energy sources to displace oil, which he says will be renewables. He wrote, "The only longer-term price relief and net benefit to the economy will come when either we reverse recent history and start to find more oil more cheaply, which will be like waiting for pigs to fly, or when cheaper sources of energy displace oil."

Mr. Grantham's analysis of the past and his outlook for the future is based on a study of the relationship between U.S. average hourly manufacturing earnings and the price of a barrel of oil from the end of the Great Depression until now. (We tried replicating his chart as shown in Exhibit 2 in an attempt to bring it current, but we failed. We came close, but our work created several unusual data points – primarily higher values in the early 1940's and in 1998-1999, suggesting that the price data we used may have been different from that used by Mr. Grantham. Having dealt with Mr. Grantham in the past, we will accept his chart as accurate.)


Exhibit 2. Phases of Oil Affordability and Wealth Creation (Sourcde: GMO)


As Mr. Grantham pointed out, in 1940 one hour's work for an American engaged in manufacturing could buy 20% of a barrel of oil. Twenty percent of an oil barrel equals roughly eight gallons. Since one gallon of oil contains the energy equivalent of 200 to 300 man-hours of labor, eight gallons would mean 1,600 to 2,400 man-hours of labor, a significant achievement. As shown within the circle labeled the Golden Era of Income Gains, the affordability of oil increased at a steady rate beginning in 1940 such that by the end of1972, one hour's work controlled 1.1 barrels of oil, over a five-fold increase in about 33 years. Mr. Grantham calls this "the greatest surge of real wealth in U.S. history."

Note that beginning in 1972, when America's oil self-sufficiency ended, OPEC's power grew, leading to the First Oil Shock (1973's Arab Oil Embargo) and eventually the Second Oil Shock (1979's Iranian Revolution), after which oil affordability fell to a new low. Between 1979 and 1999, peak oil affordability was re-established, but this time the improvement was less smooth and it was achieved during a period of falling oil prices. Another recent study pointed out that after 1981, the price of oil declined for the next 17 years, bottoming out at $13 a barrel in November 1998. Adjusted for inflation, this was the lowest price for oil since the 1940's when its affordability began to climb. What troubles Mr. Grantham is the trend in oil affordability observed since the end of the last century. Since then, affordability has now fallen to where it was in 1940.

Another key development has been what has happened to the trend in worker productivity throughout the modern era, and how it relates to the evolution of oil affordability. As oil affordability was improving between 1939 and 1972, oil intensity per person was increasing, but productivity per man-hour increased at the rapid rate of 3.1% a year. Since 1972, oil affordability has fallen and oil usage per person has declined, but productivity per man-hour has also declined such that the average increase for this entire period was only 1.1% a year. Mr. Grantham suggests that the difference in these long-term productivity rates is extremely significant. As he points out, at a 3.1% rate of increase, $1 will grow to $21 in 100 years. But at 1.1%, in the same length of time, $1 will barely grow to $3. Also very disturbing is that since 2000, the average annual productivity increase has been 0.8% a year!

While Mr. Grantham can't definitively link these two trends, he notes that the data is compatible with the thesis that falling oil affordability has dominated our energy equation and poses a serious threat to the nation's income and wealth generation capability. One may want to take that relationship a step further and ask whether it may help to explain why U.S. (and possibly even global) economic growth has remained so weak since the bursting of the Internet bubble in 2000, despite the best efforts of our monetary and fiscal authorities to pump up growth. So does this relationship have implications for how the oil and gas industry may change?

If we are destined for oil affordability to stay at such a low level and thus condemn our economy to perpetual slow growth, it is hard to see how oil prices can rebound anytime soon. On the other hand, we know that the cost of finding new oil supplies is rising, a favorite point of Mr. Grantham's. Just how much can oilfield technology limit that increase, or could it hopefully reverse it? Many people believe the shale revolution has significantly altered the oil industry, but the more important question may be whether this change has set our energy business on a new, permanent course of unlimited supply growth, or whether we merely are enjoying some additional time to effect a transition to the next energy source to power the world. This is Mr. Grantham's position. He wrote in his newsletter article, "What I'm trying to describe here is on one hand a remorseless and historically unprecedented rise in the costs of delivering oil to the marketplace, which is sapping economic strength globally, and on the other hand (and simultaneously) what will be the beginning of an accelerating transference of demand away from oil under the impact of surprising technological progress in alternative energy."

If you are a Saudi Arabian oil official, you have to be concerned by Mr. Grantham's projection for the future for the oil industry. He admits that with the addition of fracking to the equation, "the outlook for oil and energy is the most complicated puzzle I have ever come across." His outlook has to be terrifying for Saudi oil officials. "My guess is that oil prices will bounce around for most or all of the next 10 to 15 years as first one side of this tug of war moves ahead and then the other, with perhaps another 2008-type spike (or two) in the price of oil, after which prices will plateau and decline as electric vehicles take over, and one by one, oil's remaining uses are slowly replaced." If you are a newly-minted exploration and production or an oilfield service company CEO you have to be worried that Mr. Grantham's predictions are correct. But maybe your career will be over by then. But what about your pension and stock option wealth?

Another issue confronting oil and gas companies is whether they have been entrenched in the mal-investment phase of the industry's business cycle. This is the phase when "irrational exuberance," to borrow a term coined by former Federal Reserve Chairman Alan Greenspan, takes over and capital is literally thrown at "sure" projects that ultimately turn out to be disasters. Some interesting work on the topic of mal-investment and its potential implications for future economic activity and risks has been conducted by Louis- Vincent Gave of Gavekal Dragonomics Global Research. In a piece Mr. Gave penned late last year, he leaned on work done by Josh Ayers of Paradarch Advisors showing what has happened to capital spending by the oil and gas sub-components of the Standard & Poor's 500 Stock Index beginning in 2006. Notice from the chart in Exhibit 3 that the share of total capital spending was firmly within the 3% to 4% range during 1992-2006. Following 2006, that share began climbing as oil and gas prices took off. After reaching 8% during the 2008-2009 financial crisis and resulting recession, spending climbed further reaching 10% in 2014 as a decade of extraordinarily high oil prices convinced oil company managements that there was no end in sight to profitable investment opportunities.

But as the chart in Exhibit 4 shows, starting in 2006, returns began declining despite the capital spending faucet being wide open. We are well aware of the debate over the financial management of a number of E&P companies who continually overspent their cash flows, but were able to tap the debt and equity markets to raise capital along with receiving injections of funds from private equity investors and even from some of the largest oil and gas companies in the world who had initially missed the shale plays. Many of these companies are in distress, so maybe we are seeing the verdict on that debate.

Exhibit 3. Oil Industry Capital Spending Hit Record in 2014(Source: Gavekal)                             Exhibit 4. Oil Industry Guilty of Poor Capital Stewardship (Source: Gavekal)













A key question Mr. Gave asks is whether we have reached "peak demand" for oil? He is not sure, but if we have, he wonders whether we are destined to have to live through years in which markets and investors need to digest the past handful of years of misallocation of capital by the oil industry. So when we read the comments by Doug Suttles, CEO of Encana Corp. (ECA-NYSE) at the time of his year- end earnings report, during which he announced a reduction in the company's capital spending plans for 2015 to between $2 billion and $2.2 billion from its December 2014 projection of $2.7 billion to $2.9 billion, that he was reluctant to cut his budget further but would rather focus on other "financial options" to protect the company's balance sheet and oil and gas production ambitions, we were surprised. Mr. Suttles said his reluctance to cut spending further was because his strategy depends on developing four North American unconventional resources plays and he doesn't want to jeopardize the plan. He plans now to raise $1 billion of new equity.

Mr. Grantham and Mr. Gave have given us a lot to consider as we think about how the next few years will play out for the oil and gas business. We wonder whether any of these thoughts are being discussed in the boardrooms of energy companies. We suspect they are not being considered as the recent successful efforts of the major oil companies to raise billions in new debt, Canada's Cenovus (CVO-NYSE) to sell C$1.6 billion in new equity, and private equity funds to complete record fund-raising efforts dedicated to energy investments have many executives focused more on what it will take to get through the next few months rather than thinking about steps to enhance or protect shareholder value for the long-term. Slashing and burning is a tactic for survival but not a strategy for dealing with the failure to properly manage capital. Resolving that failure, while gutting one's organization, will make it extremely difficult to deal with an industry future dictated by slower underlying growth.

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 and planning for the future. The newsletter is published every two weeks, but periodically events and travel may alter that schedule. As always, I welcome your comments and observations. Allen Brooks


The U.S. Natural Gas Market is Like Ol’ Man River

PPHB-logoAn Excerpt from 'Musing from the Oil Patch' September 23, 2014
By Allen Brooks, Managing Director, PPHB

The domestic natural gas market "just keeps on rollin' along." Last week's storage injection of 90 billion cubic feet (Bcf) essentially matched the guestimates of the experts (91 Bcf) and brings the total volume of gas in storage to 2,891 Bcf. The gas injection rate continues to closely follow our forecasting model that is based on the weekly injections during 2003. If this season continues to track 2003's pattern, the industry should reach 3,427 Bcf of storage – a very comfortable level heading into the 2014-15 winter. As we have pointed out before, barring a repeat of the severe winter of 2013-14 with its several polar vortex extreme Arctic temperature events, virtually any other winter experienced during the past 20 years would leave the industry with close to 1,000 Bcf of gas in storage at the end of the heating season.

What is quite interesting is that based on either the weekly storage injections of last year or the 2003 season the industry will wind up with virtually the same volume of gas in storage. The difference between the two outcomes is that by following the 2003 pattern, the industry would wind up 21 Bcf ahead of merely matching last year's remaining weekly injection volumes.

So far this year, the industry has injected 2,069 Bcf of gas into storage reservoirs, which is within 100-150 Bcf of the total injected during most of the "large" storage- build years. Importantly, the industry is within 350-425 Bcf of matching the record injection volumes achieved during the past 20 years - those years being 2001 and 2003. As there are seven weeks still left in the injection season, surpassing the vast majority of the large injection years would seem to be a reasonable goal.

Depending on the early fall weather, it is quite possible that 2014 might attain the crown for being the largest seasonal storage injection since 1994.

Given the high level of concern existing at the end of last winter questioning the ability of the gas industry to rebuild storage, what the industry has accomplished so far this year has been remarkable.

We attribute the industry's success rebuilding gas storage volumes to a combination of a cool summer throughout most of the populous regions of the country and the continued high growth in natural gas production as a result of the shale revolution.

The key to where the industry ultimately winds up on storage volumes will depend on how it does compared to the weekly injections of either 2003 or 2013. When we compare the weekly injections against our favorite 2003 bogey, we notice that in recent weeks, despite very strong injections that have actually matched or even outperformed the analysts' consensus estimates, 2014 has trailed slightly. The next two weekly injection results will be comparing against 100 Bcf injection weeks in 2003, a level we have not witnessed since early in this injection season. Therefore, for 2014 to outperform our model, it will take stronger weekly injections during the latter few weeks of the injection season.

Exhibit 9. Comfortable Storage Depends On Heat


Source: EIA, PPHB

If the remainder of the injection season tracks either 2013 or 2003, we can see that this year will have made a significant gain in closing the gap between where storage volumes started and the average of the past five years. While the industry won't meet that average, it is noticeable how the 5-year average is fairly close to the 20-year maximum, demonstrating the impact of the warm winters during the past few years that have significantly skewed the short-term average. If 2014's gas storage volume attains our target, it will wind up slightly above the mid-point of the 20-year minimum and maximum range, a significant accomplishment given that it started at almost exactly the 20-year minimum volume.

Exhibit 10. Gas Storage Headed Toward Comfortable Level


Source: EIA, PPHB

Natural gas prices continue to bounce around between $3.75 and $4.00 per thousand cubic feet based on the latest projections for weekly weather and temperatures. This price range reflects the market's comfort that there will be adequate supply heading into winter, which has negated the need for high prices to shed gas demand. The key questions for the gas market moving forward are what sort of winter we will experience and if we will have an early and severe cold wave. After that, gas price questions quickly become ones about the longer term outlook for natural gas supply and demand, and in particular, how much liquefied natural gas (LNG) export will occur, what happens to the fuel mix for powering the nation's electricity, will the anticipated industrial revival tied to using natural gas actually materialize and, importantly, what is the gas supply outlook. Over the next few issues of the Musings we plan to examine these longer term questions.

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 and planning for the future. The newsletter is published every two weeks, but periodically events and travel may alter that schedule. As always, I welcome your comments and observations. Allen Brooks

Contact PPHB:
1900 St. James Place, Suite 125
Houston, Texas 77056
Main Tel: (713) 621-8100
Main Fax: (713) 621-8166

PPHB 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.

NOIA’s Position on Offshore Contractor Regulation Shifts

PPHB-logoAn Excerpt from 'Musings from the Oil Patch'
By Allen Brooks, Managing Director, PPHB

At the recent annual meeting of the National Ocean Industries Association (NOIA) held in Washington, D.C., there was a presentation by David Bernhardt of Brownstein Hyatt Farber Schreck dealing with "Regulation of Contractors," an issue we have written about extensively in the past. The issue relates to whether the federal government, through its Bureau of Safety & Environmental Enforcement (BSEE), has the power to regulate offshore contractors in addition to its power to regulate oil and gas company lessees.

We were surprised by the presentation as we had assumed that NOIA had already accepted the view that the government had the power to regulate offshore contractors. As the presentation unfolded, we were surprised by its thrust as it mirrored our position questioning the legality of the regulatory power expansion. More important in our view, was the question of why offshore service company CEOs had been reluctant to challenge this power grab. At least, we thought, they should have challenged the failure of BSEE engaging in a rulemaking process that would address what the rules and regulations would be. This rulemaking procedure is firmly established in administrative policy. We advocated that NOIA and offshore contractors should force BSEE to engage in a rulemaking process in order for everyone to have a say in the establishment of the rules and regulations that would govern offshore operations. Without this guidance, contractors were exposed to ex post actions, significantly changing the risk profile for operating offshore. A particularly sinister aspect of this regulatory overreach is the requirement that contractors now have joint and several liability for all other contractors' and the lessee's operations, necessitating a change in insurance coverage. We were frustrated that the NOIA leadership seemed to acknowledge the heightened risk for operating offshore but was reluctant to move forward to challenge the government over the policy overreach when it had a non- confrontational opportunity to do so through demanding a rulemaking process.

During the presentation to NOIA, we learned it had agreed to file an amicus brief in support of a challenge to BSEE's regulatory overreach from a contractor who had been served with a Notice of an Incident of Noncompliance (INC), the procedure for fining a company for an offshore working violation. The NOIA leadership is now more concerned about the evolution of this regulatory expansion and saw the challenge to the INC as a vehicle to lodge their objection. Some service company CEOs say they are now more concerned about the potential for being subject to INCs, especially after a statement by Mr. Bernhardt during his presentation that when the Interior Department was asked to submit its estimates for revenue and expenses for the government's budget, Interior indicated it anticipated generating half its INC fee income from contractor INCs. According to Mr. Bernhardt, in the past year BSEE handed out seven INCs to contractors and 8,000+ INCs to operators/lessees. Those two statements suggest that substantially more INCs will be given to contractors in the future and that the fines may be greater, or BSEE will serve fewer INCs on operators/lessees.

We are happy that NOIA has finally acknowledged that the playing field for offshore contractors has been significantly altered in an adverse manner. We are unhappy that NOIA and the contractors failed to utilize a less adversarial venue to make its case. Supporting someone charged with an infraction is a less clean, and probably a less successful way to make progress. NOIA and its members still can push for greater clarity over the legality of BSEE's regulatory expansion, but more importantly it can force BSEE to follow the established rulemaking process that would enable industry input into the rules and regulations that will govern working offshore. As they say, knowledge is power.

We always ask contractor CEOs whether they would like to have input into the rules and regulations that are going to govern the business. While they answer yes, they then have been reluctant to act to gain greater clarity and to be positioned to add input into the rules being created by BSEE. We suggest this reluctance has contributed to increased enterprise risk that may not be fully appreciated by executives and directors. Over the past five years, the Obama administration (the same administration that altered the offshore regulatory environment) has reinterpreted and selectively enforced laws and rules. That record should be a wake-up call for CEOs to become more actively involved in helping define the rules and regulations for offshore operations that will govern their companies. Maybe the NOIA meeting marks a new chapter in offshore contractor relations with BSEE. We hope this chapter isn't tied exclusively to an administrative challenge to an INC.

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 and planning for the future. The newsletter is published every two weeks, but periodically events and travel may alter that schedule. As always, I welcome your comments and observations. Allen Brooks


The Oil Industry’s Era of Austerity – Part Two

PPHB-logoAn Excerpt from 'Musings from the Oil Patch'

By Allen Brooks, Managing Director, PPHB


As the major oil companies struggle with how best to boost their profitability in an era of rising oilfield costs, business models are being adjusted. The changes are a reflection of managements' attempts to change the culture of their organizations. The most popular theme is to split a company's business into separate units with different investment and operational characterizations. For example, a popular way to split an integrated oil company is to put the most capital-intensive businesses – refining, petrochemicals, transportation and marketing – all in one basket, while the exploration and development business sits in another. That approach was popularized a few years ago by Marathon Oil (MRO- NYSE) and ConocoPhillips (COP-NYSE). The strategy was recently criticized by Archie Dunham, former CEO of Conoco at the time of its merger with Phillips Petroleum. His reasoning for disagreeing with this structure was that the capital-intensive businesses generated large cash flows that helped fund the capital needs of the E&P business.

Lately, a new business model is being promoted. That model involves splitting off the shale resource portion of a company's E&P operations into a separate unit in an attempt to mimic the structure, and presumably the operations, and hopefully the profitability, of an independent oil and gas company. The thinking behind this move is that the philosophy driving successful shale exploiters is quite different from that needed to exploit conventional oil and gas plays. For the major international integrated oil companies, this rationale may prove successful. What it takes to be successful in hunting for and developing elephant-type fields in deepwater and remoter egions of the world is considerably different from success in the domestic shale basins where the emphasis is on finding the optimal drilling and completion techniques and then repeating them over and over and over again with a goal of driving costs down. The strategy is the equivalent of buying bespoke goods versus mass produced items.

The two major oil companies who have recently embraced this new business model include Royal Dutch Shell (RDS.A-NYSE) and BP Ltd. (BP-NYSE). It remains to be seen how long it takes for each company to establish these new business units. In the back of the minds of many observers is the question of whether these moves are initial steps toward completely severing ties, i.e., selling or spinning off the entities. Our question with this business model structure is whether a corporate culture can be redesigned to achieve a different goal?

Exxon Mobil Corp. (XOM-NYSE) attempted a culture shift when it purchased XTO Energy a few years ago. At the time the deal was announced, observers questioned how ExxonMobil would be able to retain the key XTO managers who were used to a high degree of freedom to experiment, which is often found in smaller, independent oil and gas companies, as opposed to the monolithic and highly structured enterprise of its new parent. ExxonMobil's approach was to retain XTO's offices and management and to move ExxonMobil's shale staff in. So far this shale investment has yet to financially pay off as envisioned by ExxonMobil's management. Fortunately, the company has avoided the embarrassment of having to write down the value of its shale investment despite continued low natural gas prices and CEO Rex Tillerson's lament in 2012 that the company was "losing its shirt" in shale gas. The fact ExxonMobil has not taken an asset impairment charge as many of its peers have caused the Securities and Exchange Commission (SEC) to question the company about how it was able to avoid that fate.

According to a Wall Street Journal blog in early February, the company responded to the SEC inquiry stating that placing a value on wells that pump oil and gas for decades requires considering many factors, including future events. For example, the company has had approved a liquefied natural gas (LNG) export terminal that once in operation could lift the value of its domestic natural gas resources above the current price and, importantly, future prices as suggested by quotations in the futures market. Whether that reflects true conviction or significant leverage over the company's auditors is difficult to know.

Another way in which producers are addressing their reduced profitability is to attack their cost structures. Royal Dutch Shell says it plans to begin using cheaper Chinese oilfield equipment in order to lower operating costs. This would be a significant cultural adjustment as oil company purchasing departments are mandated to find the lowest cost equipment as long as it meets industry and company specifications. If the company has not been using Chinese equipment, the question is why?

This Chinese equipment strategy reminds us of Shell's "Drilling in the Nineties" program designed to cut E&P costs. The approach was that oilfield service companies needed to bundle all its drilling and completion offerings into a single package and then price the entire package cheaply. The problem was that Shell's drilling engineers, responsible for the success of wells and fields, wanted to make sure they could get the best equipment and services to ensure their success. If the service company that won the contract only had, for example, the number three ranked drilling fluids needed, the Shell engineer would arrange to purchase the number one product from a different service provider.

We will never forget a discussion we witnessed dealing with Shell's program that occurred at an early 1990s annual meeting of the International Association of Contract Drillers (IADC). At the end of the back and forth among the drillers about the pros and cons of Shell's program, one elderly gentleman, the president of a long-time West Texas contract driller, stood up and said, he didn't understand what all the fuss was about since this approach had been going on for decades – it was called turnkey drilling! Everyone laughed and as if a light bulb went on, the discussion ended. Drilling in the Nineties eventually disappeared only to be replaced by "Best in Class" in which the producer or driller selected the best vendor in each supply category.

The battle over price versus quality of drilling and completion equipment and services has always gone on and the winner depends on the relative tightness of the market. The tighter the market, the better it is for service companies. Likewise, the looser the market, the better it is for producers. The common thread of all the various drilling and service contracting initiatives tried in the industry was how they fostered consolidation within the oilfield service industry. That may be the same outcome this time, too.


It’s Official – Oil Industry Enters the New Era of Austerity

PPHB-logoAn Excerpt from 'Musings from the Oil Patch' March 18, 2014
By Allen Brooks, Managing Director, PPHB

2 weeks ago, Chevron (CVX-NYSE), the second largest oil company, held its annual analyst meeting at which time the company's management laid out its plans for the next five years, including projections for capital spending and oil and gas production growth. The meeting followed on a presentation at the IHS CERA Week conference in Houston by Chevron CEO John Watson in which he proclaimed that today's $100 a barrel oil is the equivalent of the past's $20 a barrel oil. By that he meant that the oil industry must now figure its budget outlooks based on the need for oil prices to stay around the $100 a barrel level in order for the company to generate the necessary cash flow to support spending plans and for projects to offer future returns to meet or exceed required investment hurdles. Mr. Watson has talked about the impact on his business of rapidly escalating costs for finding and developing new oil reserves, which is why he says the company now needs that
$100 a barrel price. Chevron is the latest major oil company to implicitly declare that the oil industry has entered a new era – one marked by higher costs and more disciplined capital investment programs that will require higher oil prices. Capital discipline forces companies to sacrifice production growth targets on the altar of increased profitability in order to boost returns to shareholders. What does this new era mean for the oil and gas business? Equally important, what does it mean for energy markets?

Chevron now projects it will produce 3.1 million barrels a day of oil equivalent (boe/d) in 2017, down from a target of 3.3 million boe/d that the company established in 2010 and reiterated to the analysts last year. If Chevron attains its target, it will have increased production in the interim by 19%, a not inconsequential gain. Mr. Watson attributed the reduction in the company's output target to lower spending for shale wells due to the fall in North American natural gas prices, higher volumes of oil going to the host countries where the company operates under production-sharing arrangements, and "project slippage." Mr. Watson also indicated that the company would raise $10 billion from the sale of assets, up from its previous target of $7 billion. The company plans to sell oil and gas fields and acreage to raise the funds.

The Chevron outlook mirrors that presented earlier by the industry's largest company, Exxon Mobil (XOM-NYSE), at its annual analyst meeting. There, not only did ExxonMobil CEO Rex Tillerson announce a reduced production target, but he also said that the company would cut back its capital investment program. While neither the world's number one nor number two oil companies signaled that the changes in their targets were the result of the industry entering a new era, their actions and similar ones by several of its smaller sisters do suggest that reality.

BP Ltd. (BP-NYSE) announced it was going to split off its shale operations into a separate company, still wholly-owned by BP, in an attempt to transform the operation into a more nimble explorer and developer of shale properties. If mimicking the organizational structure of larger independent oil and gas operators was BP's goal, one has to wonder what structural impediments necessitated the total separation of the unit. Maybe the move made it easier for BP's senior management to highlight the drag of its shale business and establish the entity as a stand-alone business. It may also be advertising the unit's potential in order to attract a joint venture partner or another energy company's investment.

The strategic moves by ExxonMobil, Chevron and BP fit with the efforts that Shell (RDS.A-NYSE) is making to improve its financial performance. The company is constraining its capital spending and reassessing the economic attractiveness of every exploration and development project. Another large oil company that recently made a strategic move was Occidental Petroleum (OXY-NYSE). The company is planning to spin off its California oil and gas assets and operations into a new company for its shareholders, while the remaining corporation is picking up stakes and moving its headquarters from Los Angeles to Houston where it maintains significant operations. While this move may say more about the desire of OXY's management to exit the unfriendly confines of California's regulations and costs, it also says something about the future direction of the company's exploration and development focus.

We have seen similar statements about revisions to strategic plans by the large, European-based oil and gas companies – ENI (ENI- NYSE), Total (TOT-NYSE) and Statoil (STA-NYSE). These moves are being undertaken by the management teams in response to flagging performance from their huge shale investments and other challenges similar to those outlined by Mr. Watson.

We were intrigued by the decision by Chevron to boost its oil price outlook from $79 a barrel for Brent crude oil to $110 per barrel. This move is designed to help the financial outlook for the company's earnings and to offset the reduction in the production target. The oil price assumption is consistent with the average Brent price for the past three years, but it is at odds with the trajectory for prices derived from the futures market, which call for lower levels in the future. We wonder whether this price-target revision will rank with their statement about the future course for natural gas prices a few years ago when the major oil companies jumped on the shale gas bandwagon. Their timing essentially marked the top for gas prices as North American gas prices collapsed due to the surge in gas output. This would not be the first time major oil company planning departments incorrectly projected the course of global oil prices.

Strategy adjustments by major oil companies are seldom quickly reversed even when near-term industry trends suggest an adjustment should be made. If the newly defined financial discipline mantra demanded by investors is followed and industry capital spending is restrained, and possibly falls, there will be ramifications in the energy market. If Mr. Watson's declaration, as echoed by other oil company CEOs, is true, then the cost of finding and developing new reserves is too high and the pressure to drive down oilfield service costs will grow more intense. We may now be witnessing the fallout from that discipline in the offshore drilling business where the expansion of the global rig fleet with more sophisticated and expensive rigs, necessitating higher day rates, is leading to near-term "producer indigestion." Could the offshore drilling industry be on the precipice of a significant wave of older rig retirements in order to sustain demand for its new, expensive drilling rigs currently being delivered without contracts?

Another question for the industry is who will supply the risk capital for exploratory drilling, both on and offshore, if the majors pull back their spending? Onshore, for the past few years, a chunk of that capital has been supplied by private equity investors who have supported exploration and production teams in start-up ventures. They have also provided additional capital to existing companies allowing them to purchase acreage or companies to improve their prospect inventory. Unfortunately, the results of the shale revolution have been disappointing, leading to significant asset impairment charges and negative cash flows as the spending to drill new wells
in order to gain and hold leases has exceeded production revenues, given the drop in domestic natural gas prices. Will that capital continue to be available, or will it, too, begin demanding profits rather than reserve additions and production growth?

The amount of capital flowing into the oil and gas business is extremely important for the future growth of the nation's oil and gas output since shale wells experience sharp production declines in the early years of their production. A series of questions flow from that production profile: What will happen to oil and gas prices in the medium-term if drilling slows and production rapidly declines? Will manufacturers who currently are building billions of dollars-worth of new plants designed to capitalize on cheap American energy find their investment returns not what they anticipated? How will they react? Will first-mover advantages in this manufacturing renaissance become a disadvantage? What about the billions of dollars targeting new liquefied natural gas (LNG) export terminals? Will we actually have the volumes of natural gas to export, and especially at the low prices projected that are anticipated to give American gas a competitive advantage in European and Pacific gas markets?

These questions should be raised at the same time the national debate about exporting domestic crude oil is commencing. There are various subtleties in that debate that are often lost in the broad debate themes. For example, how quickly can the U.S. refining industry build new refineries or expand existing ones in order to use more of the light, sweet crude oil coming from the tight shale oil formations? If the refining expansion doesn't keep pace with the growth of light oil, then there could be a cutback in drilling for shale oil that will certainly result in a sharp reduction in the current bullish outlook for U.S. oil production as shown by the significant increase in future output estimated by the Energy Information Administration in its 2014 outlook versus its 2013 projection.

A cutback in oil drilling would also reduce the volume of associated natural gas being produced, which could result in an unexpected spike in gas prices. For some time, U.S. oil producers have been able to secure export licenses to send oil out of the country, primarily to Canada, but will that avenue continue to exist and can it be expanded to prevent a shutdown in shale oil drilling? The political debate over exporting domestic crude oil is being described as 310 million American consumers versus a handful of oil company CEOs with fat pay packages. We doubt the industry can win that battle.

Those are only some of the critical questions that must be asked and answered as the oil and gas industry transitions into the next era of its existence. Much like the performance of the United States economy, the oil and gas business has internal momentum that will keep it going as managements reassess its future. We have been watching the industry over the past couple of years with one historical perspective in mind – the generational change underway in the executive suites of energy companies. While we are not denigrating the experience levels or intellect of the new CEOs, we are merely reflecting on the past periods when industry leadership changes occurred. Those transitions often resulted in the new leaders having to make their own "learning mistakes" like their predecessors did. That may be an important aspect of the industry transition currently underway.

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 and planning for the future. The newsletter is published every two weeks, but periodically events and travel may alter that schedule. As always, I welcome your comments and observations. Allen Brooks


Understanding Oil Industry Restructuring Currently Underway

PPHB-logoAn Excerpt from Musings From the Oil Patch, February 18, 2014
By Allen Brooks, Managing Director, PPHB

The weak financial results reported by the oil majors for 2013's fourth quarter and full year should be viewed within the context of the industry's structural transition that is likely to last for some time. With the advent of activist shareholders, management changes and financial pressures due to the costs of the shale revolution, companies have been forced to re-examine their business models and corporate focus. Many analysts and investors are narrowly focused on the near-term impact these restructuring steps are having on company cash flows and production growth. While these are important near-term considerations, they should be viewed from a higher level and with a long-term perspective. From that level, the first observation is that the restructuring movement commenced several years ago and it began within smaller companies in this industry group in response to the desire of their managements and boards of directors to improve their corporate performance in light of the more limited capital and investment options they had available. Now, the restructuring movement has moved up the food chain and is being driven by the actions of larger integrated oil companies.

The changes they are making are partially in response to how the American shale revolution is impacting the dynamics of the domestic crude oil and natural gas markets, and that are now beginning to impact the petroleum industry globally.

The current obsession on the industry's restructuring actions was driven by the mid-January earnings pre-announcement from Royal Dutch Shell (RDS.A-NYSE), which marked the company's first such earnings miss in a decade. The prior miss was the result of a corporate scandal in the form of an overstatement of oil and gas reserves, which ultimately cost several senior executives their jobs. Shell's press release announcing that its fourth quarter earnings would be $2.9 billion, down 48% from the $5.6 billion earned in the same quarter a year ago, and importantly $1 billion below the consensus analyst estimate, created significant turmoil within the investment community. Shell also said that its 2013 full-year earnings would total approximately $19.5 billion, compared with $25.3 billion in 2012, which reflected a disappointing year.

Effective January 1st, Shell now has a new chief executive officer, Ben van Beurden, a 30-year employee of the company and an unconventional choice to run the company given his downstream career. While some investors suggested Shell was merely "kitchen sinking" the bad news to provide a relatively clean slate for the new CEO, Mr. van Beurden said that the company's performance in 2013 was "not what I expect from Shell" and that changes would be made. He went on to tell investors that his focus would be on improving Shell's financial results and "achieving better capital efficiency," code words for re-establishing an earnings growth trajectory. It is also code for cutting and re-ordering capital spending, streamlining the business and shifting priorities, which probably got employee attention.

Subsequent to the earnings warning, the financial media began evaluating the performance of the major oil companies. This led to several articles about the challenges major oil companies were encountering in managing their mega-projects needed to increase their oil and gas output. Many of these high-profile projects have been the subject of corporate reviews over the past six months due to cost-overruns that are raising questions about the projects' financial viability. Chevron's (CVX-NYSE) Gorgon project off the coast of Australia to produce and export liquefied natural gas (LNG) and co-owned with ExxonMobil (XOM-NYSE) and Royal Dutch Shell, has seen its cost estimate escalate from the original budget of $38 billion to $54 billion, a roughly 45% increase. This is only one mega-project, but the oil majors have seen similar cost escalations at other mega-projects around the world driven by labor shortages, regulatory requirements and delays, and bad weather.

The surprise announcement last May that Shell CEO Peter Voser, the company's former chief financial officer, would retire at the end of 2013 after less than four years at the helm set in motion not only a search for a new chief executive but also a high-level review of the company's investment performance and capital spending plans. Mr. Voser was highly regarded by investors as Shell had outperformed all but one of its oil company peers since he became CEO. In July, Shell's directors surprised the investing community by naming Mr. van Beurden the new CEO. He was the head of Shell's refining operations and had been a decade-long head of its chemicals operations, but he had also held a position for two years evaluating and trying to improve the operating performance of downstream operations. In anticipation of taking over, Mr. van Beurden spearheaded a review of Shell's capital investment plans including a proposed gas-to-liquids plant targeted for Louisiana that was canceled and its investment in Arrow, a LNG project in Australia that was deferred. A decision about constructing a petrochemical plant in the U.S. Northeast to capitalize on the growing gas and liquids output from the Marcellus and Utica formations was postponed.

When Shell reported its earnings, Mr. van Beurden announced a change in direction for the company, partially reflecting the company's capital spending review and clearly a statement about its view of the company's needs for the future. Shell will curb its spending, temper its growth plans, increase divestments and restructure parts of the business. At the same time, Shell's confidence in the future was reflected by the decision to increase its dividend by 4%. At the same time, however, the company cut total capital spending 20% below 2013's level and targeted increasing organic investment by 8% to $35 billion. The company is stepping up its divestment program with plans to sell an additional $15 billion of assets during 2014 and 2015.


The Amazing Race For First Offshore Wind Farm Continues

PPHB-logoAn Excerpt from 'Musings from the Oil Patch'
By Allen Brooks, Managing Director, PPHB

As we ushered in the New Year last week, we thought of the fact that America was supposed to have had wind turbines whirling offshore by now. We were reminded of this prediction by an article discussing the end of the federal production tax credit for wind power generation that died at year-end, along with some 54 other tax breaks Congress couldn't find time to renew. An interview with an American Wind Energy Association (AWEA) representative lamented the death of the tax break, which has had a history of expiring periodically during its 20-year life, only to be resurrected the following year.

The AWEA representative pointed out that the Internal Revenue Service was allowing projects that were 5% or greater completed by year-end to claim the tax credit helping the economics of their projects. That meant by having spent 5% of the total cost of the project or that they can demonstrate continuous construction activity, the credit can be claimed and retained for the life of the credit. That generous ruling was made because the tax credit had barely survived the previous year-end termination, which had disrupted investment in ongoing and planned wind power projects, so the government wanted to make sure that all the projects launched late in the year could still achieve the tax credit threshold so as not to discourage wind farm developers from moving forward with new projects during 2013. One of those projects benefitting from this ruling is Cape Wind's offshore Massachusetts wind farm located in Nantucket Sound.

Cape Wind, which will have 130 of the 3.6 megawatt (MW) state-of- the-art Siemens AG (SI-NYSE) offshore wind turbines capable of generating 420 MW of power, will cost an estimated $2.6 billion to construct. The contract to purchase the wind turbines was signed December 23rd. Last Friday, Cape Wind's largest source of financing recommitted to the project even though the developers missed the year-end deadline established by the lender to identify
other investors. PensionDanmark had offered to provide a mezzanine loan commitment of $200 million, which it is willing to keep in place. According to Christian Skakkebaek, a senior partner at Copenhagen Infrastructure Partners, which PensionDanmark is using to invest in the project, "We are keen to see the project being
realized and reaching financial close later in 2014."

The controversial offshore wind farm that still expects to be the first in the nation, filed its initial permit application in 2001. It would now appear to be sometime in 2014 before the financing to construct the project will be finalized. The Cape Wind web site suggests start-up of the wind farm during 2016. We remain fascinated that a green- energy project with a 25-year contract to sell its power to a local utility at a price substantially above the current market price for alternative green energy supplies, and at a multiple of the cost of natural gas-fired power, which also possesses a guaranteed annual price escalation built into the contract terms, continues struggling to arrange financing. Are lenders worried about demand trends in the power market, or the bad experiences being reported by some of the European wind farms, or are the economics of this project questionable? Mr. Skakkebaek stated there is "still some work to be done before our mezzanine loan commitment of $200 million can be made unconditional."

Since he did not specify what work remained to be done, we are only left with our questions and no answers



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 and planning for the future. The newsletter is published every two weeks, but periodically events and travel may alter that schedule. As always, I welcome your comments and observations.  Allen Brooks


Safety Statistics Reporting Could Impact Offshore Regulation

PPHB-logoAn Excerpt from 'Musings from the Oil Patch' November 12, 2013
By Allen Brooks, Managing Director, PPHB

The Department of Labor is considering creating a publicly available database of workplace safety information of large companies. The head of the Occupational Safety and Health Administration (OSHA) and safety advocates argue that public information about injuries at the workplace will aid the government's efforts at safety enforcement. The proposal the government released last week calls for about 38,000 private companies – those with 250 employees or more – to provide a detailed quarterly report of all major injuries that occur at a worksite, including the cause of each injury. OSHA plans to release the data with personal employee information redacted on its web site.

Companies are already required to collect the safety information, to post it at their worksites and to provide injury rate summaries to government data surveyors when selected, but the statistics are not normally reported to OSHA. At the present time, around 60,000 companies a year provide injury data that is stored on OSHA's website, but that information is not complete. The new proposal will expand the reporting requirement to about 440,000 companies that must report injury and illness information.

Industry is fighting the government's proposal because the data is subject to misuse/misinterpretation that could support agendas by groups that have nothing to do with safety and health. On the other hand, regulators say they need the additional information to determine which industries and companies to target for investigations and improvements. Some safety professionals and researchers are concerned that the additional reporting requirement might lead to under-reporting injury and illness data by companies in order to make them appear safer. Will employees monitor their boss' safety reporting accuracy?

We find it interesting that recent media articles reporting on accidents and deaths of foreign workers offshore could become another pressure point for the release of accident, injury and illness statistics. In the past several years, there have been at least two accidents involving offshore platforms where four Filipino workers have died. Investigations have pointed to a lack of communication between operators and contractors and even among contractors working offshore. The 2011 extension of offshore regulation to service companies by the Bureau of Safety and Environmental Enforcement (BSEE) from its prior exclusive focus on operators/lessees has changed working relationships offshore. Now that service companies are regulated, management has a responsibility to understand how their working relationship with their clients – the oil companies – has changed and how they must adjust to the new conditions.

One of the primary changes is that the service companies can no longer be indemnified by their clients, but rather everyone operates under "joint and several" liability, meaning each party must insure against not only its own accidents but also those that might be caused by other contractors or even the operator.

The energy reporters at the Houston Chronicle have written several stories about the investigations into the safety incidents offshore. The conclusion from these investigations can be summed up by comments from Brian Salerno, the head of BSEE. He was quoted saying, "The connections between operators and contractors can probably be tightened up from a safety perspective." He also commented, "Our recent experience suggests that all offshore oil and gas operations ... carry inherent risks." But one issue that critics of safety conditions offshore point to is the current cap of $40,000 per incident per day in an environment where daily operating costs can run to several million dollars per day. They question whether that cap is sufficiently high enough to draw the attention of managements.

In the new world of offshore regulation, especially for the heretofore unregulated service companies, the altered business relationships for working offshore means service company managements need to adjust their thinking and actions. The pressure from OSHA officials seeking the release of safety data for industries and companies could further pressure the offshore oil and gas industry's operations. Welcome to the new world of offshore regulation!

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 and planning for the future. The newsletter is published every two weeks, but periodically events and travel may alter that schedule. As always, I welcome your comments and observations. Allen Brooks


The Simple Truth – BP’s Macondo Blowout by J.A. Turley

PPHB-logoAn Excerpt from ‘Musings from the Oil Patch’  May, 14, 2013

By Allen Brooks, Managing Director, PPHB

We were recently pointed to The Simple Truth by J.A. Turley as an outstanding nonfiction novel about BP’s Macondo well disaster. J.A. (John) Turley has degrees in petroleum engineering and ocean engineering from the Colorado School of Mines and the University of ThesimpletruthMiami. He started his industry career with a three-year petroleum- engineering professorship at Marietta College before entering the private sector. He spent 20 years involved in offshore drilling- and project-management with a major U.S. energy company starting in the Gulf of Mexico and then the North Sea leading him to be named manager of worldwide drilling. During this time he received additional schooling at the Harvard Business School. After a number of years as the companys senior technical officer, he elected to retire early to concentrate on writing.

Mr. Turleys use of the novel form for telling the Macondo story gave him the license to simplify a complex story, while creating three individuals that represented the roles and responsibilities of BP and Transocean. One of the individuals is a young female geologist with BP who has plans to take time off to earn a petroleum engineering degree. She uses her assignment on Transoceans Marianas and then its Deepwater Horizon rigs that drilled the initial and the fatal Macondo well to trail the BP company man (a petroleum engineer) asking questions and being educated about each and every step undertaken in drilling this well and deepwater wells in general. Her responsibility is to monitor the mud flows and the cuttings to determine when the well reaches the target formation. At the same time, her education and job responsibility puts her in the position of comprehending the impending disaster and trying to stop it before the disaster unfolds.


The book is loaded with understandable explanations of all the industrys technical terminology and their application, along with numerous illustrations and schematics of the hardware and the well’s design. After telling the Macondo story, Mr. Turley goes through detailed analysis of the mistakes and alternative actions that might have been taken to avoid the well blowout and rig destruction. The authors education, job experience and access to the numerous studies of the accident enable him to clearly set forth the simple truth of the Macondo disaster. Having studied the accident, read several of the studies and followed the media reports from the recent trial, we found this book a fascinating and educational read about the Macondo disaster and offshore drilling in general. (Click on the hyperlink above to go to Amazon to purchase the book.)

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 and planning for the future. The newsletter is published every two weeks, but periodically events and travel may alter that schedule. As always, I welcome your comments and observations. Allen Brooks


Oil Industry on Alert – Active Hurricane Season Forecast

PPHB-logoAn Excertp from 'Musings from the Oil Patch'

by Allen Brooks, Managing Director, PPHB

Earlier this month, the tropical storm forecasting team of Philip J. Klotzbach and William M. Gray, professors in the Department of Atmospheric Science at Colorado State University (CSU), released their first forecast for the upcoming hurricane season. They are calling for the season to experience “enhanced activity compared with the 1981-2010 climatology,“ meaning it will be an active storm season. Furthermore, the forecasters “anticipate an above-average probability for major hurricanes making landfall along the United States coastline and in the Caribbean.” In other words, be prepared.

Based on the work the tropical storm forecasting team has done in conjunction with the GeoGraphics Laboratory at Bridgewater State University in Massachusetts, the model predicts that there is a 72% probability of a major hurricane making landfall along the entire U.S. coastline compared to a 52% average for the past century. For the U.S. East Coast including the Florida Peninsula, the probability of landfall is 48% versus a 31% historic record. For the Gulf Coast from the Florida Peninsula to Brownsville, Texas, the probability is 47% compared to a 30% record. The model also estimates that the Caribbean has a 61% probability versus 42% historically of experiencing a major hurricane landfall. These higher than historic probabilities will have the U.S. petroleum industry on alert during the upcoming season although even with a very low probability it only takes one storm to create serious disruption and economic hardship.

The CSU forecasters are using a relatively new April forecasting model that employs four predictors they have found to have an above-average predictive value. This is the third year the forecasters have used this model, which is built on data from 1982-2010. The model incorporates the most recent and reliable data available, which the forecasters believe helps improve the model’s predictive ability. They said these four predictors helped the model to correlate with the Net Tropical Cyclone Activity (NTC) at 0.79 when all years studied are included. A drop-one cross-validation analysis yields a correlation with the NTC of 0.68. This is a more realistic view of the skill the model will have in future years. The forecasters say that this model correctly predicted above- or below- average seasons in 22 out of 31 hindcast years, a 71% average. The model’s predictions have had a smaller error than climatology in 19 of 31 years for a 61% average.

The predictors used in the model include the average sea surface temperature (SST) in the Atlantic basin in the January to March period, the sea level pressure (SLP) for March in the central Atlantic Basin and the February to March SLP in the Pacific Ocean region off South America, and the European Centre for Medium-Range Weather Forecast (ECMWF) of the SLP in the Pacific Ocean along the Equator.

Exhibit  13. Predictors Used In Hurricane  Model


Source:   CSU

The CSU forecast calls for 18 named tropical storms during the season with nine hurricanes and four of them becoming intense (major) hurricanes, meaning they are storms in the intensity range of 3-4-5. They believe that 2013’s activity will be similar to the 2011, 2010 and 2009 years with the exception of the number of intense hurricanes last year. This year’s activity would also compare with 2008, but not as intense as 2005 when there were 26 named storms and seven intense ones and 2004 with 14 named storms and six intense hurricanes.

The reason for the above-average forecast this season for tropical storms, hurricanes and intense hurricanes is because the meteorological projections call for the combination of an anomalously warm tropical Atlantic basin and a relatively low likelihood of the formation of an El Niño. To modify the forecast from the output of the model, the forecasters look to analog years. In selecting the analog years, the forecasters look for those years with similar meteorological conditions as projected for this season. None of the analog years had a significant El Niño during the peak of the hurricane season, which is the condition anticipated this year. The forecasters are anticipating that 2013 will have more activity than the average of the five analog years selected – 1915, 1952, 1966, 1996 and 2004.

Exhibit  15.  Analog Years For 2013 Storm Forecast

Year     NS       NSD     H          HD       MH       MHD    ACE     NTC

1915    6          48.25   5          30.50   3          13.75   127      129

1952    7          39.75   6          22.75   3          7.00     87        103

1966    11        64.00   7          41.75   3          8.75     145      140

1996    13        79.00   9          45.00   6          13.00   166      192

2004    15        93.00   9          45.50   6          22.25   227      232

Avg.     10.4     64.80   7.2       37.10   4.2       13.00   151      15



4/10/13     18        95.00   9        40.00   4          9.00     165      175



Source:   CSU, PPHB

The next forecast update will be produced at the beginning of June and it will be interesting to see what modifications are made. The development of El Niño could alter the forecast meaningfully, but the likelihood is that this year will be more active – consistent with the more active tropical storm phase for the Atlantic basin. If the CSU forecast on landfall potential proves correct, the energy industry will need to be vigilant and is likely to have several episodes when offshore operations will need to be shut down and crews evacuated. That will mean the Gulf will produce less oil and gas this summer than potentially anticipated now by operators and forecasters. All of these possibilities need to be considered when making projections about how the domestic energy business will play out in 2013.

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 and planning for the future. The newsletter is published every two weeks, but periodically events and travel may alter that schedule. As always, I welcome your comments and observations. Allen Brooks