Musings: Oil Industry On Alert - Active Hurricane Season Forecast

This opinion piece presents the opinions of the author.
It does not necessarily reflect the views of Rigzone.

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.

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 comparison of the April forecast with the most recent six years is displayed in Exhibit 14.

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.

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.

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.

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Musings: China And The Importance Of The South China Sea

The world has been riveted with the drama unfolding in the northern Pacific region as North Korea rattles its rockets and threatens war. One of the key players in this drama is China, a long-time supporter of North Korea. China has many conflicting geopolitical objectives, some of which are driven by the nation's need for increased energy supplies and raw minerals to power its economy in order to support its 1.2 billion in population.

China realizes it has emerged as a super power, and with that status it must demonstrate its power meaning it must establish dominance in the Pacific region.

Economically, militarily and politically, China has power throughout Asia from Vietnam to North Korea. What it hasn't had until recently is a significant naval presence. That situation is changing as China has built it first aircraft carrier and other sophisticated naval vessels including submarines. At the same time, China has reiterated its long-standing claim over the South China Sea, and with it the country's claim over whatever mineral and energy resources might be present.

China's claim over most of the South China Sea is based on its 1946 undefined claim – the nine dashes on a map.

The South China Sea is a large and strategic body of water. Exhibit 3 shows the numerous agreed boundaries negotiated between South China Sea neighboring countries since the late 1950s. It also shows the declared limits claimed by countries beginning with the 1946 Chinese claim. While there are many geopolitical implications due to these conflicting declarations, our purpose is to examine the significance of the South China Sea to China from an energy perspective.

The initial consideration is the location of possible oil and gas deposits. The Energy Information Administration (EIA), coupled with the resources of other research firms, has put together a map of the possible oil and gas deposits in the South China Sea. A number of these areas have been explored and continue to be explored and developed. Those include deposits offshore Vietnam, China, Brunei and Malaysia. If one re-examines the nine dashes encompassing the area of the South China Sea claimed by China (Exhibit 3, page 5), some resources claimed by Vietnam, Brunei and Malaysia could be claimed by China setting up tension amongst the countries. (See Exhibit 4.)

However, as the EIA shows, these resources are not truly significant in the global scheme of resource deposits. According to the EIA, the undiscovered oil resources of the South China Sea, excluding the Gulf of Thailand, Indonesia's Java, Borneo and Sumatra basins, and the Solu Sea, are slightly greater than those of Europe at roughly 10 billion barrels of oil. The South China Sea ranks seventh in all geographic regions and along with Europe represents a minor increment of the world's undiscovered oil resources.

The South China Sea ranks in the same position relative to Europe and the other regions of the world with respect to undiscovered natural gas resources.

The South China Sea has about a quarter of the estimated undiscovered natural gas of North America, a mature conventional gas resource region, but with a rapidly growing unconventional shale gas potential. At the end of the day, all the proved oil and gas reserves plus all the possible undiscovered ones still leaves the region as a bit player in the world's energy business.

If the oil and gas resource potential of the South China Sea is so limited, why does China find it must demonstrate power in the region? The need to show that as an emerging super-power and with the second largest economy on the planet, China must show strength. At the same time, China is also a significant importer of energy and raw materials, all of which are extremely important for the health of the country, its people and its government. China is targeted to surpass six million barrels per day (mmb/d) of crude oil imports during the second half of 2013. At the same time, the United States, the globe's largest oil importer, will be bringing in less than 6 mmb/d of crude sometime early in 2014, dropping the country into second place behind China on the list of the world's largest oil importers.

For China that is rapidly becoming the world's largest oil importer, protecting that flow of oil becomes a prime consideration of the government. Note in Exhibit 7 (page 8) that nearly 13 mmb/d of oil, almost 15% of total world oil consumption, flows into the Strait of Malacca near Singapore, one of the world's well-established shipping chokepoints. About 11 mmb/d of that oil flow goes beyond Singapore and Thailand and toward Hong Kong, China, South Korea and Japan, making protecting these shipping lanes imperative for the health of those economies.

An equally important energy trade is the flow of liquefied natural gas (LNG), much of which comes from Australia and Southeast Asia, but with a growing volume coming from the Middle East. LNG is likely to become an important fuel for China who has relied upon coal-fired electricity to power its economy with the attendant problem of serious pollution problems in its major cities. In 2011, China imported 12 million metric tons (mts) of LNG, equivalent to 1.5 billion cubic feet per day (Bcf/d). China was projected to import 16 million mts in 2012, or roughly 2.0 Bcf/d, and to reach Japan's 56.6 million mts of LNG consumed in 2012 by 2020. To handle that increased volume, China is planning to construct 15 new LNG receiving terminals to go along with the five already in operation. Given the North American shale revolution, the potential for LNG exports from Canada and the United States has become a real possibility. The opening of a widened Panama Canal by 2015 means LNG carriers coming out of the Gulf of Mexico will have a shorter shipping route to Asia then if they were forced to circle South America in order to reach the Pacific market. Two other developing natural gas industry trends will also impact the global flow of LNG. One is the development of the recent huge gas discoveries in East Africa. The Asian region is the target market for the natural gas recently found offshore Mozambique and Tanzania, but the energy industry is also excited about exploration opportunities in Madagascar, Kenya and Uganda, any and all of which would likely flow to Asia.

Longer term there is also the wildcard of China's gas shale potential. Estimates are that China has the world's largest shale gas resources. If it successfully develops these resources, China could rapidly shift from being an LNG importer to becoming an LNG exporter. Both situations put a premium on China being able to insure the safe passage of LNG tankers, either to terminals in China to offload cargos or to load cargos destined for world markets.

As President Barack Obama has indicated his foreign policy initiatives have pivoted toward Asia, the geopolitical tensions in the region will be elevated, not just because of what North Korea is doing. The United States has entered into upgraded trading relationships with our Asian friends, so we must demonstrate our willingness to stand by them when and if they have to confront China over its South China Sea territorial claims. At the same time, the U.S. Navy must demonstrate our strength in the region to prevent the appearance of the U.S. being perceived as a "paper tiger" by other nations in the world. Defense Department budget cuts coupled with a shrinking and aging fleet of naval vessels is hurting our ability to fulfill the many and varied missions assigned to the Navy. Any change in that course will take considerable time.

While oil and gas developments in the South China Sea will be of interest to the petroleum industry and investment community, the real story of this region is its strategic placement within the flow of energy globally and its importance in the geopolitical struggle between the two leading super-powers – the U.S. and China. With a better understanding of the true importance of the South China Sea to China's economic and political stature, one should be better able to understand the significance of actions and events likely to unfold over the next few years.

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.

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Musings: The Gulf of Mexico Is Back Based On Lease Sale Results

Two weeks ago the Department of the Interior reported the results of the Central Gulf of Mexico lease sale 227, which, based on the total amount of money oil and gas companies bid, suggested the industry is bullish on prospects in this region. As usual, the media focused on the total dollar figures and the bidding intensity among companies over a few tracts, but it may have missed some of the underlying trends that are shifting and will shape the Gulf's future.

The media focused on the total dollar figures and the bidding intensity among companies over a few tracts

Some 52 oil and gas companies submitted 407 bids on 320 tracts offered by the government. BP plc did not submit a bid, although they were told by the Interior Department that they could. BP is currently prohibited from securing government contracts due to the settlement terms of the Macondo oil spill. The Interior Department told BP they could submit a bid and after a review would be informed whether they were able to be awarded the tract. We assume BP declined to invest the time and effort in what was likely to be nothing more than an exercise. What we don't know is whether BP bid as a partner with others, although their legal status could impact the award status. The 320 tracts bid on represented only 4.5% of all the tracts offered, which was the smallest percentage since 2001, as shown in Exhibit 6 on the next page.

The 320 tracts bid on represented only 4.5% of all the tracts offered, which was the smallest percentage since 2001

When the results of the sale are examined from the perspective of the total number of tracts bid on, the post-2000 period has generally demonstrated a downward trend, although there have been some very successful lease sales such as in 2007 and 2008. Those years appear to have been an aberration from the general trend of bidding in a mature oil and gas province. The high sale results were consistent with the speculative fever that gripped the U.S. and global economy immediately prior to the 2008 financial crisis.

BOEM altered some of the terms of the lease bids from prior sales

Federal officials, such as Interior Secretary Ken Salazar and Bureau of Ocean Energy Management (BOEM) Director Tommy Beaudreau, cheered the results of the sale, and pointed out that comparisons of this Central Gulf of Mexico sale to the prior one in 2012 should be made with caution since the prior sale reflected pent-up industry demand due to the absence of a sale in 2011 following the Macondo oil spill. Additionally, BOEM altered some of the terms of the lease bids from prior sales. Deepwater acreage minimum bids were boosted to $100 per acre compared to prior sale amounts of only $37.50 an acre. The minimum bid hike came following extensive analysis by BOEM showing that deepwater leases with high bids of less than $100 per acre experienced virtually no exploration and development. The deepwater tracts leased in this sale also carried escalating rental rates and tiered durational terms with relatively short base periods followed by additional time under the same lease if the operator drills a well during the initial period. This is the federal government's attempt to make sure that acreage leased offshore is drilled rather than becomes a Congressional talking point whenever gasoline prices soar about how many idle offshore leases the oil industry holds.

Extensive analysis conducted in the mid-1980s showed that between 1974 and 1984, the industry always acquired lease acreage that was never drilled

While we have not seen the BOEM analysis, we would be cautious about interpreting the data. Since the federal government shifted its offshore leasing program to area-wide lease sales in 1983, oil and gas companies have often purchased acreage with minimum bids as they attempt to lock up sufficient acreage spreads to cover geological/exploration theories they planned to test. Extensive analysis conducted in the mid-1980s showed that between 1974 and 1984, the industry always acquired lease acreage that was never drilled. That analysis shocked many in the industry who had always assumed that, prior to the introduction of area-wide leasing, all the acreage ever leased offshore was drilled. The practice of not drilling all leased tracts mushroomed once the industry was freed from the "nomination process for identifying acreage to be leased" in order to test unconventional geologic theories. If the theory proved wrong with a test well, then multiple tracts were often condemned and never drilled. We tend to believe that the shift to area-wide leasing in the Gulf and away from the acreage nomination system previously in effect contributed to the successful development of sub-salt plays, Lower Tertiary plays and the entire deepwater phenomenon.

We attribute this consistency to the exploration philosophy of the modern oil and gas industry that companies are in the business of replacing and growing their reserves and production and they must continue to reinvest in the business every year if they expect to remain in business long-term

A measure we follow when attempting to assess the success of a Gulf of Mexico lease sale is the ratio of bids made to tracts bid on. We have examined this ratio going back to the very first Central Gulf sale but more importantly since area-wide lease sales began in 1983. Exhibit 8 shows the tracts bid on, the number of bids made and the ratio of those figures for each Central Gulf sale since 1983. The sale results should be read from right to left, but what they show is how relatively consistent the ratio has been over this 30-year period. With commodity prices rising and falling and the fortunes of the industry ebbing and flowing, one might have expected greater variability in the bids-to-tracts trend. We attribute this consistency to the exploration philosophy of the modern oil and gas industry that companies are in the business of replacing and growing their reserves and production and they must continue to reinvest in the business every year if they expect to remain in business long-term. This investment trend goes counter to the "speculator" view of oil company managements. Under that theory, oilmen would not be bidding during periods when oil prices were high and rising but would only bid when commodity prices were low. Yes, high oil prices, which provide incremental cash flows for the companies, are often the justification for accumulating greater exploration acreage inventory than when industry times are lean. But the stability of the bids-to-tracts ratio suggests greater, and more consistent, financial discipline than the speculator thesis.

The shallow Gulf of Mexico segment may be on the cusp of a revival after having been ‘left for dead’ by the emergence of the shale revolution onshore

The most notable figures to come from the lease sale results were the number of bids in deep and shallow water depths. According to data from BOEM, there were 131 bids for tracts located in water depths of 1,600 meters of water depth or greater but 85 bids for tracts in less than 200 meters of water depth. Those figures suggest to us that the shallow Gulf of Mexico segment may be on the cusp of a revival after having been 'left for dead' by the emergence of the shale revolution onshore. If accurate, it means better times for many of the more traditional domestic suppliers of offshore oilfield services. It has been the absence of activity in shallow water that has retarded the Gulf of Mexico recovery, but that may be about to change.

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.

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Musings: Natural Gas Output Falls In December; Start Of A Trend?

This opinion piece presents the opinions of the author.
It does not necessarily reflect the views of Rigzone.

The Energy Information Administration's (EIA) survey of natural gas production from the Lower 48 states for the month of December 2012 showed the first decline in output since March of that year. With the continued decline in drilling rigs targeting natural gas formations, analysts are encouraged that possibly we are witnessing the first results of the drilling slowdown. The EIA's commentary associated with the release of the data, however, mentioned weather related factors impacting gas output, especially in the associated gas production from the Bakken where an early and severe winter caused a drilling and well completion slowdown. Additionally, many producers ran out of budget money before the end of the year and were forced to slow activity. If nothing else, however, the slowdown in gas output reinforces the phenomenon the industry may soon be confronting, which is the need to ramp up drilling activity to offset the steep decline in existing well production due to the nature of shale gas wells.

Overall, the initial estimate of gross natural gas production for the entire United States fell just about 1 billion cubic feet (Bcf) in December. Alaskan gas production actually rose about 0.2 Bcf while output in the Gulf of Mexico fell almost as much (-0.14 Bcf), meaning that virtually the entirety of the production decline occurred in Lower 48 basins. If we examine the revision to the prior monthly's initial production estimate, there was a reduction of 0.32 Bcf, which suggests the December production decline may only have been about 0.7 Bcf, but of sufficient size to be meaningful. Before analysts get too excited about this potential change in trend and what it might mean for natural gas prices, a new report from natural gas research firm, Bentek Energy, suggests that 2013 and 2014 will be a replay of the past several years – growth in production rather than a decline. The firm's forecast, however, calls for a slowing in the rate of increase in gas production during the next two years compared to the rate of growth experienced in the prior two years.

According to Bentek, natural gas production in the U.S. rose 3.6%, or by 1.6 Bcf per day in 2010 and increased by an average of 3.5
Bcf/d in 2011-2012. They are projecting that overall gas output will grow by 2 Bcf/d in 2013, as nine key shale basins will grow by 4.9 Bcf/d, which will be offset by other production falling by 2.9 Bcf/d. In 2014, the firm sees production increasing by 3.4 Bcf/d. An interesting point in the historical data is that in 2011 offshore gas output fell by 1.2 Bcf/d and then by another 0.9 Bcf/d in 2012. Bentek sees offshore production declining by only about 0.3 Bcf/d in 2013 and reaching steady output in 2014. If we were to exclude the impact of the decline in offshore production in 2011-12, the average annual output increase was about 4.3 Bcf/d, or nearly 0.8 Bcf/d more coming from onshore basins. By the end of 2014, Bentek foresees gas output above 70 Bcf/d, up from current production of slightly be low 65 Bcf/d.

Bentek's forecast for output is based on three primary factors. These include: debottlenecking of geographic regions where output has been constrained by a lack of infrastructure; operators continuing to focus on wet gas and associated gas from oil plays; and continued improvement in drilling rig efficiencies. The impact of the last two factors is shown in several charts from the Bentek forecast report that crystalize their views.

The chart in Exhibit 11 shows the impact of wet gas (green) output on total incremental natural gas production beginning in 2010 and continuing through the 2014 forecast period. As the chart shows, associated wet gas was only a minor contributor to gas output in 2010 but grew in 2011 as the impact of low natural gas prices drove operators to emphasize oil and wet gas formations. With natural gas prices continuing to languish in 2012, that trend became more pronounced with expected results. Because of the strong focus on natural gas liquids (NGLs) and crude oil due to high world oil prices and better investment returns for operators, Bentek sees wet gas production growing as we move through 2013 and 2014. Part of the strength in NGL and oil demand and their prices is due to debottlenecking Bentek assumes will occur based on the list of new pipeline and gas processing facilities either being built or planned to be built in the coming months.

The last major trend is the impact on shale gas costs from improvements in drilling. Exhibit 12 contains a chart showing the number of horizontal wells drilled since 2008 (blue columns), the number of horizontal rigs working (red line) and the average number of wells drilled per rig per month (black dotted line). The wells per month line in most impressive showing how after about a three-year downward trend between 2008 and 2010, the number rose in 2011 and remained essentially stable throughout the year but then started a steady upward climb throughout 2012. This rise in rig performance reflects not only improved knowledge about how and where to drill and the greater use of pad drilling facilities, but also the impact from the growing fleet of new AC (electric) rigs that bring greater capabilities for drilling deeper and longer horizontal wells.

Improvements in drilling in the Bakken have been meaningful as shown in Exhibit 13. Since the first quarter of 2010, the average time to drill a well has declined roughly 15%, although from the fourth quarter of 2010 the decline is much more significant – off nearly 40%! As the average rig can drill more wells per year and more rigs are moving into the Bakken, wells drilled have jumped in the past several quarters - from around 375 wells per quarter to 500 wells and then to a 600-wells per quarter rate for the final three quarters of 2012. The question is can the industry operate more drilling rigs in the region and will those rigs be capable of continuing to drill wells in fewer days in the future?

Last summer, the North Dakota Department of Mineral Resources presented an expected case for the future number of drilling rigs (red columns) working in the state's Bakken formation and the number of producing wells (green columns). As can be seen in Exhibit 14, the forecast calls for a small increase in the number of drilling rigs for 2013 and again in 2014, with rigs remaining flat in 2015 before spiking to a peak of just over 250 rigs in 2016. From that point the rig count begins a modest downward stepping pattern until it reaches a low point of 50 rigs in 2036 where it remains through the balance of the 2050 forecast period. As a result of the boom in drilling between 2010 and 2024, the total number of Bakken wells rises sharply from 5,000 to about 35,000. Thereafter, due to the decline in the active drilling rig count, the climb in the number of producing wells is modest reaching almost 40,000 wells in 2050.

A big challenge for producers in the Bakken is the lack of pipeline infrastructure to move associated natural gas production from the
region. Many people are familiar with the NASA photo of the United States at night showing the gas flaring in the Bakken (red) compared to the lights of Minneapolis, Minnesota on the right hand side of the picture. This picture rivals ones from the past showing the huge volumes of gas being burned in Nigeria and Russia that could be seen from space.

A chart from the North Dakota Department of Mineral Resources shows how the percentage of natural gas produced in the state is
burned. As the chart in Exhibit 16 shows, gas flaring was relatively minor until about 2005 and then it grew to about 24% in 2008 before falling 10 percentage points as a pipeline was opened up. From about 14% in 2009, the percentage of gas burned rose to the 35% area where it remains today awaiting more pipeline capacity and liquids-processing plants being built.

The Bentek natural gas production forecast relies on the continuation of the triumvirate of factors that have made oil shale plays as successful as they have been to date. Debottlenecking of various key producing basins appears a safe bet since it is based on projects already approved and in many cases already under construction with attractive returns. A continuation of improvements in drilling efficiency appears less secure as it depends on the drilling industry converting the balance of its old, conventional rig fleet into a new, AC-based one. That means higher day rates for working rigs in order for contractors to justify the investment in new rigs. What will higher dayrates mean for well economics? What happens to these oil and wet gas plays should oil prices fall from their current lofty levels? These latter considerations could impact the economics of shale drilling and thus gas output that would negatively impact the Bentek forecast since it is based on economic models employing 12-month forward strip pricing for crude oil and NGLs. The one offset to this logic is the dedication of large integrated and independent producers to drill through the period of poor economic returns because they believe in the eventual recovery of oil and natural gas prices that will reward them for their strategy.

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.

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Musings: Building Sand Castles - BSEE's Regulatory Over-Reach

This opinion piece presents the opinions of the author.
It does not necessarily reflect the views of Rigzone.

On April 20, 2010, an explosion occurred on Transocean's Deepwater Horizon, a nine-year old semisubmersible drilling rig working to drill the first well on BP plc.'s Macondo prospect in the Gulf of Mexico. The explosion, resulting fire and eventual sinking of the rig set off a chain of events that unleashed the greatest oil spill in U.S. oil industry history. The Deepwater Horizon disaster resulted in the deaths of 11 workers, while 94 crewmen were rescued.

Two days after the explosion, an oil leak was detected from the well and industry and government officials shifted into high gear in an attempt initially to contain the spill and ultimately design a way to permanently seal the well. Numerous attempts were made to try to close the blowout preventer shear rams, pump drilling mud and cement into the well, place a containment dome over the well to catch the leaking oil and burning off some of the oil that rose to the surface. Other ideas were considered and discarded. Eventually a relief well was drilled that intersected with the original well bore and cement was pumped in to permanently plug the leaking well. On September 19, 2010, U.S. Coast Guard Admiral Thad Allen (ret.), the incident commander for the Macondo spill, declared the well "effectively dead" and of no future danger to the Gulf of Mexico.

The offshore oil and gas industry was disrupted not only by the disaster but also from the federal government's actions to shut down all offshore drilling until forced by the courts to allow shallow water drilling activity and eventually deepwater drilling to resume. Another impact of the Deepwater Horizon disaster was the revamping of the federal government's natural resource regulatory structure, taking the Interior Department's Minerals Management Service and breaking into three parts in order to eliminate conflicting missions – one (Office of Natural Resources Revenue) to manage the royalty and revenues derived from the nation's resources, another (Bureau of Ocean Energy Management) to manage the sustainable development of the nation's offshore resources, and the third (Bureau of Safety and Environmental Enforcement) to regulate safety and environmental oversight of offshore oil and gas activities.

The Bureau of Safety and Environmental Enforcement (BSEE) became actively involved in examining the causes of the Deepwater Horizon disaster, which has led to revisions to existing offshore safety and operating procedures. As part of the establishment of BSEE, the federal government announced it had the power (and duty) to regulate all companies involved in offshore resource activity, which was a significant extension of its regulatory power. Prior to this announced expansion of its regulatory scope, the MMS/BSEE only regulated through its contractual relationship with offshore operators (lessees). Offshore service companies conducting drilling, construction, transportation and maintenance activities on operated leases were regulated through Incidents of Non Compliance (INCs) sent to the lessee. Now, following the Deepwater Horizon accident and resulting Macondo oil spill, two service companies – Halliburton and Transocean - were issued INCs for the first time ever. The authority for BSEE to issue those INCs was derived from the regulators' broad interpretation of the scope of the agency's regulatory powers.

Beyond the question of issuing INCs was problem of BSEE not having offered rules for regulating offshore service company operations. There are strict procedures established under the Administration Procedures Act (APA) that stipulate how federal government agencies are to lay out new industry regulations, the right of industry participants to comment on the proposed rules, and for the federal government to consider these comments in any final rule-making activity. BSEE has yet to promulgate any rules, which would provide an opportunity for companies to comment, discuss and negotiate with the bureau before they become codified.

The latest development in this regulatory jurisdictional issue was the February 19th hearing in the United States District Court for the Eastern District of Louisiana where Judge Carl Barbier approved Transocean's Partial Consent Decree with the U.S. government. Transocean agreed to pay $1 billion in civil penalties for violations of the Clean Water Act and to take other remedial measures. Transocean has two years to pay the fine and to institute a series of operational safety and emergency response improvements on its rigs. This court-approved settlement resolves all other pending government agency enforcement actions and penalties against Transocean, including the four INCs issued by BSEE in October 2011 for the Macondo disaster. Those INCs (and HAL's INCs) had been on appeal with the Interior Board of Land Appeals.

The negotiated settlement requires Transocean to abandon its appeal of the INCs without an admission of liability for the claims in the INCs and for the U.S. government not to assess any civil or administrative penalties based on the INCs. Importantly, BSEE is not dismissing the INCs. This means that BSEE can claim that its first enforcement action against an offshore contractor successfully resulted in the issuance of INCs. The requirement that Transocean abandon its appeal avoids any judicial review of BSEE's action. The settlement terms raise the question of whether BSEE is concerned about its ability to withstand judicial scrutiny of the expansion of its regulatory authority.

According to a newsletter published by the Houston-based law firm Legge, Farrow, Kimmitt, McGrath & Brown, LLP, "This issue will likely remain unresolved until a court reviews BSEE's current attempts to directly regulate contractors, or until BSEE drafts appropriate regulations and submits them for notice and comment by the industry as required under the Administrative Procedures Act." We would agree with the first conclusion about the potential for a court review clarifying BSEE's authority. However, we doubt that BSEE has any intention of issuing draft regulations for the industry to comment on soon since it believes it already possesses all the authority it needs to issue INCs, even though service companies do not know the rules they must operate under. For this reason, the request by BSEE for comments about its draft safety culture policy statement offers the best opportunity for industry representatives to comment not only on the policy statement but also on other issues involving offshore regulation.

Offshore service company managements need to understand they now are regulated, but without any clear understanding of what the rules are they are operating under and will be judged against. Most energy executives think of industry regulation as that of utilities where government agencies oversee pricing, returns companies can earn and how they operate. In this case, the regulations are only dealing with how a company operates, but that can have a significant impact on financial returns. Operating in the dark is not a sound business strategy, and if it comes as a result of ignoring the opportunity to seek clarity then managers have only themselves to blame if they get caught in this Kafkaesque environment.

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.

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Musings: PwC Says Shale Oil 'The Next Energy Revolution' - Really?

Economists with the worldwide accounting firm of PricewaterhouseCoopers LLP (PwC) have just published an interesting and thought-provoking analysis of the long-term impact of shale oil on the global economy. While one might question some of the shale oil production numbers that evolve from the PwC analysis, the final couple of pages of the report, which focus on "opportunities and challenges for governments and companies" and touch on topics we have been devoting significant thought to with respect to the implications of the growth in output from unconventional oil and gas plays, is what we found most intriguing.

PwC begins its report with a brief review of the history to date of shale oil and shale gas in the United States. The economists point out that shale oil production has grown from 111,000 barrels per day (b/d) in 2004 to 553,000 b/d in 2011, or an annual growth rate of 26%, albeit starting from a very small base. We know shale oil production increased further in 2012. The oil production increase in North Dakota alone, where the Bakken tight oil formation dominates the output, rose by 233,805 b/d last year. Furthermore, the Energy Information Administration (EIA), in its supplemental information supporting its latest Short Term Energy Outlook (STEO), is calling for an increase in tight oil output between November 2012 and December 2014 of 1.13 million b/d, or nearly all of the projected total U.S. crude oil production increase during this period of 1.26 million b/d.

This optimistic outlook for tight oil production is driven both by the technical success producers are having in extracting the output and the high global price of oil. These two factors have contributed to the EIA estimating that the shale oil resources in this country have increased from 4 billion barrels in 2007 to 33 billion barrels in 2010, and we suspect the estimate will go higher when the next estimate is released. PwC says the EIA is estimating that U.S. shale oil production will grow at a much slower rate in the future than in the past, but it will reach 1.2 million b/d of output by 2035, or 12% of the nation's projected oil supply. They comment that this projection may be conservative given that other analysts are forecasting tight oil production to reach upwards of 3-4 million b/d by 2035. PwC believes that tight oil production will make the largest contribution to total U.S. oil supply growth by 2020, which would be consistent with the EIA's outlook in its latest STEO cited above. The implication of this forecast is that increased shale oil production will displace a significant volume of waterborne crude oil imports to the U.S., estimated to be potentially as much as a 35-40% decline.

In PwC's view, this scenario could lead to future oil prices being significantly lower than projected in current forecasts. Just how much lower the price might be becomes an interesting exercise in forecasting the global growth in shale oil production and the reaction of the leading conventional oil producers – primarily OPEC members. At the present time, the EIA estimates oil prices will reach $133 per barrel in real terms by 2035, which is a higher projected price than the International Energy Agency (IEA) forecasts, which is $127 per barrel.

PwC believes that global estimates of shale oil resources will be revised upwards significantly over time. That belief is based on the past pattern of shale oil and shale gas resource estimate changes in the United States. As a result, PwC believes that "global shale oil production has the potential to rise to up to 14 million barrels of oil per day by 2035," which would represent approximately 12% of global oil supply then. This production growth will have an impact on global oil prices according to PwC, depending on how OPEC members and Russia respond. PwC has developed two scenarios for predicting future oil prices – one that allows for OPEC to respond by lowering its output and the other with no OPEC response. In the former scenario, PwC sees the global oil price maintaining an average price of around $100 per barrel in real terms, while in the latter case it falls to $83 per barrel. Based on these two scenarios, PwC sees the potential for future global oil prices to be $33-50 per barrel lower than the EIA's reference case of $133 per barrel in 2035, in real terms. This reduced oil price is significant and raises numerous questions for governments and companies, while also creating significant opportunities and challenges.

By using the National Institute Global Econometric Model, PwC attempts to project the impact of its two price scenarios (a decline of $33 or $50 per barrel in real oil prices) on global economic activity. They conclude that at today's Gross Domestic Product (GDP) values, there could be "an increase in size of the global economy of around $1.7-2.7 trillion per annum. This could imply a rise by 2035 in average global GDP per person of between $230 and $370 per annum (at today's prices) relative to the EIA baseline case with minimal shale oil production." If the PwC price outlook proves correct, there will be a significant positive impact on future global economic activity and the wealth of various countries.

The economic model's results suggest that India and Japan could each see an increase in their GDP of between 4% and 7% by the end of the projection period. PwC sees other net oil importers such as the United States, China, Germany and the UK gaining between 2% and 5% in GDP over the period. On the other hand, OPEC member countries and Russia could experience deterioration in their current account balances due to the lower oil price. PwC points out, however, that the financial damage lower oil prices might cause for Russia could be offset if the country elects to exploit its large estimated shale oil resources. That would certainly favor ExxonMobil given its growing relationship with Russia's Rosneft Oil Company.

In the conclusion to its report, PwC briefly explores some of the implications growing global shale oil production will have on energy markets, energy companies and governments. It is the positive implications, on balance, from growing shale resource exploitation that gives us increased confidence that the long-term outlook for the United States will be positive, despite near-term domestic economic and political fears and growing concerns over the future geopolitical outlook. The magnitude of our optimism is likely to be shaded by the political, geopolitical and economic policies and actions of our leaders, but we don't doubt that the United States will reach the next decade in a surprisingly stronger relative position than most prognostications suggest today.

Given PwC's belief in the potential for significant oil shale production and resulting lower future oil prices, the firm's economists say that the financial case for renewables becomes relatively less attractive. There is little doubt about that reality, but the argument for developing renewable energy projects has rarely been about their financial viability, but rather about the social responsibility from building them. To the extent that government mandates for greater investment in renewable energy projects increases, then the nation's future economy could be somewhat smaller as energy capital could be misdirected into investments that are uneconomic and have a greater likelihood of being abandoned in the future much like the wind farms built during the 1980s in California.

Lower oil prices will also impact the pace of development of more expensive and less environmentally attractive oil supplies such as Arctic and oil sands resources. While these two resources currently are being attacked on environmental grounds, their vulnerability to low returns on capital investment may be what actually curtails their future development. Given this trend, oil companies will need to reassess their current portfolios against lower future oil prices. This reassessment may become a catalyst for accelerated merger and acquisition activity as large, integrated oil companies target undervalued, financially challenged smaller oil and gas companies possessing attractive resource holdings. The lower cost of capital and greater financial resources to withstand periods of increased commodity price volatility, coupled with greater R&D capabilities to reduce finding and development costs gives the large, integrated oil companies a significant competitive advantage.

Companies that are targeting offshore oil and gas developments exclusively may find a need to seek diversification of focus. That goes for both oil and gas producers and oilfield service companies. Here again, M&A activity may be the easiest and fastest way for single-purpose entities to become more broadly diversified. In the same vein, the governments of OPEC members and other net oil and gas exporters may need to reassess the impact on their budgets of reduced oil prices and possibly lower oil production. While there always remains the possibility that reduced oil prices will stimulate greater oil consumption in the future, the changing demographics of the global population and recent legislative initiatives to reduce energy consumption will bake into the future energy outlook a flattish energy demand growth profile.

The big winners in the PwC scenarios are those companies and industries that use oil and its by-products in their own output. Lower energy prices have already produced a resurgence of on-shoring previously exported businesses. Changing demographics in historically cheap labor markets such as China and Asia has led to U.S. manufacturing companies restarting domestic production of capital equipment and durable goods. Importantly, the belief in the potential of abundant natural gas supplies and thus cheap feedstock costs is leading to a revival of the domestic petrochemical industry and the emergence of a nascent liquefied natural gas exporting business. As it took decades for these companies to abandon the rapidly growing high-cost energy environment that characterized the U.S. during the latter part of the last century and the early years of the current one, manufacturers will not be quick to shift out of the U.S. at the first uptick in energy costs as they perceive that our nation has built a long-term global competitive cost advantage.

So while we rail against the destructive economic and political decisions being made in our seats of government today, we see an opportunity for the domestic GDP pie to be larger in the future; just how much larger will be determined by the decisions of politicians in the near-term. At some point in the distant future, we anticipate looking backwards and marveling at how resilient the U.S. economy proved to be and how it overcame the many dire predictions of its demise due to the idiotic political and economic actions of our rulers. We will probably wind up tipping our hat to the benefits created by the great American shale revolution begun by the son of Greek immigrant parents from Galveston, Texas – George Mitchell. While many people would call him a true entrepreneur, and he was/is, based on our encounters with him, we would say he was more like Nellie from South Pacific fame that Rodgers and Hammerstein deemed "A Cockeyed Optimist."

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Musings: PwC Says Shale Oil 'The Next Energy Revolution' - Really?

Economists with the worldwide accounting firm of PricewaterhouseCoopers LLP (PwC) have just published an interesting and thought-provoking analysis of the long-term impact of shale oil on the global economy. While one might question some of the shale oil production numbers that evolve from the PwC analysis, the final couple of pages of the report, which focus on "opportunities and challenges for governments and companies" and touch on topics we have been devoting significant thought to with respect to the implications of the growth in output from unconventional oil and gas plays, is what we found most intriguing.

PwC begins its report with a brief review of the history to date of shale oil and shale gas in the United States. The economists point out that shale oil production has grown from 111,000 barrels per day (b/d) in 2004 to 553,000 b/d in 2011, or an annual growth rate of 26%, albeit starting from a very small base. We know shale oil production increased further in 2012. The oil production increase in North Dakota alone, where the Bakken tight oil formation dominates the output, rose by 233,805 b/d last year. Furthermore, the Energy Information Administration (EIA), in its supplemental information supporting its latest Short Term Energy Outlook (STEO), is calling for an increase in tight oil output between November 2012 and December 2014 of 1.13 million b/d, or nearly all of the projected total U.S. crude oil production increase during this period of 1.26 million b/d.

This optimistic outlook for tight oil production is driven both by the technical success producers are having in extracting the output and the high global price of oil. These two factors have contributed to the EIA estimating that the shale oil resources in this country have increased from 4 billion barrels in 2007 to 33 billion barrels in 2010, and we suspect the estimate will go higher when the next estimate is released. PwC says the EIA is estimating that U.S. shale oil production will grow at a much slower rate in the future than in the past, but it will reach 1.2 million b/d of output by 2035, or 12% of the nation's projected oil supply. They comment that this projection may be conservative given that other analysts are forecasting tight oil production to reach upwards of 3-4 million b/d by 2035. PwC believes that tight oil production will make the largest contribution to total U.S. oil supply growth by 2020, which would be consistent with the EIA's outlook in its latest STEO cited above. The implication of this forecast is that increased shale oil production will displace a significant volume of waterborne crude oil imports to the U.S., estimated to be potentially as much as a 35-40% decline.

In PwC's view, this scenario could lead to future oil prices being significantly lower than projected in current forecasts. Just how much lower the price might be becomes an interesting exercise in forecasting the global growth in shale oil production and the reaction of the leading conventional oil producers – primarily OPEC members. At the present time, the EIA estimates oil prices will reach $133 per barrel in real terms by 2035, which is a higher projected price than the International Energy Agency (IEA) forecasts, which is $127 per barrel.

PwC believes that global estimates of shale oil resources will be revised upwards significantly over time. That belief is based on the past pattern of shale oil and shale gas resource estimate changes in the United States. As a result, PwC believes that "global shale oil production has the potential to rise to up to 14 million barrels of oil per day by 2035," which would represent approximately 12% of global oil supply then. This production growth will have an impact on global oil prices according to PwC, depending on how OPEC members and Russia respond. PwC has developed two scenarios for predicting future oil prices – one that allows for OPEC to respond by lowering its output and the other with no OPEC response. In the former scenario, PwC sees the global oil price maintaining an average price of around $100 per barrel in real terms, while in the latter case it falls to $83 per barrel. Based on these two scenarios, PwC sees the potential for future global oil prices to be $33-50 per barrel lower than the EIA's reference case of $133 per barrel in 2035, in real terms. This reduced oil price is significant and raises numerous questions for governments and companies, while also creating significant opportunities and challenges.

By using the National Institute Global Econometric Model, PwC attempts to project the impact of its two price scenarios (a decline of $33 or $50 per barrel in real oil prices) on global economic activity. They conclude that at today's Gross Domestic Product (GDP) values, there could be "an increase in size of the global economy of around $1.7-2.7 trillion per annum. This could imply a rise by 2035 in average global GDP per person of between $230 and $370 per annum (at today's prices) relative to the EIA baseline case with minimal shale oil production." If the PwC price outlook proves correct, there will be a significant positive impact on future global economic activity and the wealth of various countries.

The economic model's results suggest that India and Japan could each see an increase in their GDP of between 4% and 7% by the end of the projection period. PwC sees other net oil importers such as the United States, China, Germany and the UK gaining between 2% and 5% in GDP over the period. On the other hand, OPEC member countries and Russia could experience deterioration in their current account balances due to the lower oil price. PwC points out, however, that the financial damage lower oil prices might cause for Russia could be offset if the country elects to exploit its large estimated shale oil resources. That would certainly favor ExxonMobil given its growing relationship with Russia's Rosneft Oil Company.

In the conclusion to its report, PwC briefly explores some of the implications growing global shale oil production will have on energy markets, energy companies and governments. It is the positive implications, on balance, from growing shale resource exploitation that gives us increased confidence that the long-term outlook for the United States will be positive, despite near-term domestic economic and political fears and growing concerns over the future geopolitical outlook. The magnitude of our optimism is likely to be shaded by the political, geopolitical and economic policies and actions of our leaders, but we don't doubt that the United States will reach the next decade in a surprisingly stronger relative position than most prognostications suggest today.

Given PwC's belief in the potential for significant oil shale production and resulting lower future oil prices, the firm's economists say that the financial case for renewables becomes relatively less attractive. There is little doubt about that reality, but the argument for developing renewable energy projects has rarely been about their financial viability, but rather about the social responsibility from building them. To the extent that government mandates for greater investment in renewable energy projects increases, then the nation's future economy could be somewhat smaller as energy capital could be misdirected into investments that are uneconomic and have a greater likelihood of being abandoned in the future much like the wind farms built during the 1980s in California.

Lower oil prices will also impact the pace of development of more expensive and less environmentally attractive oil supplies such as Arctic and oil sands resources. While these two resources currently are being attacked on environmental grounds, their vulnerability to low returns on capital investment may be what actually curtails their future development. Given this trend, oil companies will need to reassess their current portfolios against lower future oil prices. This reassessment may become a catalyst for accelerated merger and acquisition activity as large, integrated oil companies target undervalued, financially challenged smaller oil and gas companies possessing attractive resource holdings. The lower cost of capital and greater financial resources to withstand periods of increased commodity price volatility, coupled with greater R&D capabilities to reduce finding and development costs gives the large, integrated oil companies a significant competitive advantage.

Companies that are targeting offshore oil and gas developments exclusively may find a need to seek diversification of focus. That goes for both oil and gas producers and oilfield service companies. Here again, M&A activity may be the easiest and fastest way for single-purpose entities to become more broadly diversified. In the same vein, the governments of OPEC members and other net oil and gas exporters may need to reassess the impact on their budgets of reduced oil prices and possibly lower oil production. While there always remains the possibility that reduced oil prices will stimulate greater oil consumption in the future, the changing demographics of the global population and recent legislative initiatives to reduce energy consumption will bake into the future energy outlook a flattish energy demand growth profile.

The big winners in the PwC scenarios are those companies and industries that use oil and its by-products in their own output. Lower energy prices have already produced a resurgence of on-shoring previously exported businesses. Changing demographics in historically cheap labor markets such as China and Asia has led to U.S. manufacturing companies restarting domestic production of capital equipment and durable goods. Importantly, the belief in the potential of abundant natural gas supplies and thus cheap feedstock costs is leading to a revival of the domestic petrochemical industry and the emergence of a nascent liquefied natural gas exporting business. As it took decades for these companies to abandon the rapidly growing high-cost energy environment that characterized the U.S. during the latter part of the last century and the early years of the current one, manufacturers will not be quick to shift out of the U.S. at the first uptick in energy costs as they perceive that our nation has built a long-term global competitive cost advantage.

So while we rail against the destructive economic and political decisions being made in our seats of government today, we see an opportunity for the domestic GDP pie to be larger in the future; just how much larger will be determined by the decisions of politicians in the near-term. At some point in the distant future, we anticipate looking backwards and marveling at how resilient the U.S. economy proved to be and how it overcame the many dire predictions of its demise due to the idiotic political and economic actions of our rulers. We will probably wind up tipping our hat to the benefits created by the great American shale revolution begun by the son of Greek immigrant parents from Galveston, Texas – George Mitchell. While many people would call him a true entrepreneur, and he was/is, based on our encounters with him, we would say he was more like Nellie from South Pacific fame that Rodgers and Hammerstein deemed "A Cockeyed Optimist."

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Musings: Hydraulic Fracturing Issue Encounters Protests And Movies

On Friday, January 11, a 30-day public comment period in New York State on the issue of hydraulic fracturing ended, but not without a certain amount of high-drama. The wife and son of the late Beatles star John Lennon, Yoko Ono and Sean Lennon, led a group of protestors on a visit to the Albany office of New York Governor Andrew Cuomo (Dem) and the Department of Environmental Conservation. At the latter stop, the duo, who founded Artists Against Fracking last July, delivered 50 boxes reportedly containing 204,000 comments about hydraulic fracturing.

Around the same time, Ms. Ono had an op-ed published in the Albany Times Union in which she wrote, "My husband, John Lennon, and I bought a beautiful farm in rural New York more than 30 years ago. Like the rest of our state, this peaceful farming community is threatened by fracking for gas. She went on to say, “Governor Cuomo, please don’t frack New York. Don’t allow our beautiful landscapes to be ruined, or our precious and famous clean water to be dirtied."

Sean Lennon has made the point that his father’s home, which was purchased for its beauty and serenity, would be threatened by the possible construction of a pipeline to haul natural gas from Northeastern Pennsylvania (the Marcellus formation) to New York City and New England. While he is not stating that the property would be the site of drilling and fracturing activity, but the pipeline would be needed if fracturing was allowed to occur in the region near their home.

Gov. Cuomo has been wrestling with the fracking issue for over a year while watching upstate New York’s economy languish due to fallout from the financial crisis and resulting recession. In his recent State of the State message, Gov. Cuomo made the following point about the problems of that region. "We need an additional focus on upstate New York. There have been decades of decline in upstate New York. When you look at the job growth in upstate New York, frankly, it is sad and troubling."

The Governor has been reminded of the economic benefits of shale development from a leading Democrat, former Pennsylvania Governor Ed Rendell (Dem), who allowed development of the Marcellus Shale in his state, which has contributed significantly to that state’s economic recovery. The economic benefits of shale’s development were recently pointed out by Rachael Colley and Joe Massaro, field directors with Energy in Depth, a public outreach campaign funded by the Independent Petroleum Association of America, who said, "The ‘state’ of New York State is grim. Natural-gas development could be the light at the end of the gloomy tunnel."

Gov. Cuomo says he is working on an overall energy development plan for the state and suggests that his silence on the issue and reluctance to release an environmental study on the health impacts from hydraulic fracturing should not be taken as a sign that he has reached a decision. He did, however, recently hire Richard L. Kauffman, a former adviser to U.S. Energy Secretary Steven Chu, to serve as New York’s new energy secretary. Some are interpreting the move as an indication that Gov. Cuomo is prepared to take dramatic steps on energy policy.

The Governor should recognize that a decision to support fracturing, even if restricted to just those few New York State counties that border the Pennsylvania shale development activity, will not be popular with many citizens such as those following Ms. Ono and Mr. Lennon. Ms. Ono told supporters and Rolling Stone magazine that "If they do this, there will be a class action, and the class action is going to hit everybody who is doing this. It’s going to go on and on and on. Do we want that?"

We’re not sure whether Gov. Cuomo was holding off his decision in anticipation that Matt Damon’s movie, Promised Land, would bring some clarity to the fracking issue. The much anticipated movie, which released a trailer last fall to tease potential viewers about the message of the film, arrived with a whimper – and not many positive reviews. We’ll leave the acting reviews to Hollywood-types, but having seen the movie during its second weekend of release, we suggest you save your $8 ticket money.

The movie is cute and delivers a twist at the end, which we interpreted as an attempt by Mr. Damon, who both co-authored the script and was the lead actor, to garner sympathy from the anti-fracking people in the audience. It is presented as a morality play with Mr. Damon as the "bad" guy who eventually becomes a "good guy only to suffer at the hands of both the owners of the land whose mineral rights he is trying to lease and his bosses at Global, the $9-billion-a-year natural gas company. The discussions about hydraulic fracturing are incomplete and largely inaccurate, so one should not hold out hope that the topic would be advanced by the movie.

In a movie of this type, you would expect some interesting scenes, characters and dialogue. There were a few, but often we wound up shaking our head at the illogical events and explanations or outright mischaracterization of facts. However, we found one scene early in the movie quite funny. As Mr. Damon and Frances McDormand, playing his assistant, were driving through the Pennsylvania country-side on the way to visit a local farmer, he comments on how the landscape looks like Kentucky. We laughed because when we first saw the scenery, my wife leaned over to me and said “it looks like Kentucky,” based on the farmland of the Whiskey Trail that we drove last year on our way to Rhode Island. Having Mr. Damon make the same claim literally seconds after my wife did was very funny.

The new year will certainly not lessen the focus on shale development and the role played by hydraulic fracturing. President Barack Obama’s emphasis on climate change and environmental stewardship in his inaugural address means the federal government will be energized to resolve the science of fracking and set forth a path to a cleaner and cooler environment. For a president focused on his legacy, this mission offers many opportunities to legislate, if not to govern through executive order, Mr. Obama’s preferred way to deal with an uncooperative Congress. Mr. Obama certainly hopes the message of his second inauguration day will be looked back upon much as how Walter Cronkite used to close his 1950s "You Are There" history shows: "What sort of day was it? A day like all days, filled with those events that alter and illuminate our times … and you were there."

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here