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On January 23, 2012, Chesapeake Energy announced that it would curtail drilling in shale gas plays in the United States. Subsequently, other operators have followed suit. While the outcome of this announcement is unclear, it is a signal that the industry is in distress. One can argue that this distress stems from a lack of discipline as market price began to decline.
After gas prices collapsed in mid-2008, U.S. operators continued to drill as if price did not matter. Many reasons were given to justify the economics of on-going activity including to hold acreage by production, to fulfil contract obligations to build new pipelines, and since well economics remained favourable at lower prices because of forward hedging. Now, with gas prices below $2.50 per thousand cubic feet (mcf), an adjustment in producer behaviour is overdue. Despite statements that shale gas is a profitable venture at low gas prices, it is now clear that the reality has imposed limits on these claims.

Also on January 23, the Energy Information Administration (EIA) released its Annual Energy Outlook 2012 (early release overview). It projects that gas supply will exceed consumption and the U.S. will become a net exporter by 2021. The agency also forecasts gas prices to remain below $5.00 per thousand cubic feet (mcf) until 2022.

In his State of the Union address on January 25, the President stated that the United States has 100 years of natural gas supply. While these events are not related, they reflect the dominant view among analysts that shale gas has fundamentally changed supply and price for the foreseeable future. The purpose of this analysis is to show that there may be an alternate perspective.

U.S. Shale Plays

The advent of shale plays provided an important new source of gas. Yet this new supply is characterized by high decline rates which means that wells must be continuously drilled to maintain supply. In 2001, the U.S. natural gas decline rate was about 23% and the annual replacement requirement was 12 Bcf/d when total consumption was 54 Bcf/d.

According to ARC Financial Research, $22 billion per quarter is needed to maintain domestic gas supply based on analysis of the 34 top U.S. publicly traded producers. Cash flow for those companies is $12 billion per quarter so there is a $10 billion quarterly cash flow deficit (Exhibit 3). The important factor here is that on a whole there are no retained earnings, and historically growth stems from retained earnings. Without retained earnings, companies must borrow money or sell assets into joint venture agreements to raise cash in order to drill.

While the continued drilling has been funded by debt, share offerings and joint venture agreements thus far, the trend is unsustainable given the steep decline in prices, despite some favourable hedges. Drilling, therefore, must decrease in order to shrink the present over-supply and so that prices can rise.

U.S. shale plays share many characteristics with the gold rushes of the nineteenth and early twentieth centuries. Both phenomena result from extreme promotion. Anyone can join. Every participant believes that they will get rich. Great amounts of capital are destroyed as entrants try to get a position. The bonanza is exhausted sooner than most expected (Andreoli, 2011) and few profit in the end except for the vendors that serve participants.

For several years, we have been asked to believe that less is more, that more oil and gas can be produced from shale than was produced from better reservoirs over the past century. We have been told more recently that the U.S. has enough natural gas to last for 100 years. We have been presented with an improbable business model that has no barriers to entry except access to capital, that provides a source of cheap and abundant gas, and that somehow also allows for great profit. Despite three decades of experience with tight sandstone and coal-bed methane production that yielded low-margin returns and less supply than originally advertised, we are expected to believe that poorer-quality shale reservoirs will somehow provide superior returns and make the U.S. energy independent. Shale gas advocates point to the large volumes of produced gas and the participation of major oil companies in the plays as indications of success. But advocates rarely address details about profitability and they never mention failed wells.

Shale gas plays are an important and permanent part of our energy future. We need the gas because there are fewer remaining plays in the U.S. that have the potential to meet demand. A careful review of the facts, however, casts doubt on the extent to which shale plays can meet supply expectations except at much higher prices.

One Hundred Years of Natural Gas

The U.S. does not have 100 years of natural gas supply. There is a difference between resources and reserves that many outside the energy industry fail to grasp. A resource refers to the gas or oil in-place that can be produced, while a reserve must be commercially producible. The Potential Gas Committee (PGC) is the standard for resource assessments because of the objectivity and credentials of its members, and its long and reliable history. In its biennial report released in April 2011, three categories of technically recoverable resources are identified: probable, possible and speculative.

The President and many others have taken the PGC total of all three categories (2,170 trillion cubic feet (Tcf) of gas) and divided by 2010 annual consumption of 24 Tcf. This results in 90 and not 100 years of gas. Much of this total resource is in accumulations too small to be produced at any price, is inaccessible to drilling, or is too deep to recover economically.

If half of this supply becomes a reserve (225 Tcf), the U.S. has approximately 11.5 years of potential future gas supply at present consumption rates. When proved reserves of 273 Tcf are included, there is an additional 11.5 years of supply for a total of almost 23 years. It is worth noting that proved reserves include proved undeveloped reserves which may or may not be produced depending on economics, so even 23 years of supply is tenuous. If consumption increases, this supply will be exhausted in less than 23 years. Revisions to this estimate will be made and there probably is more than 23 years but based on current information, 100 years of gas is not justified.

Shale Gas Plays May Not Provide Sustainable Supply

Several of the more mature shale gas plays are either in decline or appear to be approaching peak production.

This play is most responsible for the current over-supply of gas with the average well producing 3.3 million cubic feet per day (Mcf/d) compared to only 0.4 Mdf/d in the Barnett. It is too early to say for sure, but the Haynesville Shale may also be approaching peak production.

If some existing shale gas plays are approaching peak production after only a few years since the advent of horizontal drilling and multi-stage hydraulic fracturing, what is the basis for long-term projections of abundant gas supply?

What Publicly Available Data Indicates About Supply

Data for this analysis is from publicly available sources provided by government agencies such as the Texas Railroad Commission (TX RRC), the Louisiana Department of Natural Resources (LA DNR), the Oklahoma Corporation Commission, and the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). This data is available on web sites maintained by these agencies but is also collected and compiled for a fee by service companies, specifically IHS and HPDI (DI Desktop). All of these sources provide access to individual well, field, county, and state production.

The EIA provides valuable data on oil and gas production but not at finer than state level, and state production is only current through 2010. EIA gas production data differs somewhat from state data and from the data collected by service companies, and is generally more optimistic. The EIA uses a model to calculate gas production based on a sample of large gas producers, and then applies a correction to reconcile production with underground storage volumes.

The October 2012 difference was 1.6 Bcf/d. Although TX RRC Data indicates that Texas gas production has declined each month since March 2011, EIA reports show consistent increases. This difference is important because Texas produces 28% of U.S. gas supply (Exhibit 11). Similar differences have been noted for other major gas-producing regions. It should be noted that the EIA data in Exhibit 11 represents marketed production while the TX RRC data shows total gas production.

These accounts should have different values but also should have similar trends. The trends are similar through March 2011 but then diverge producing the present noted variance (The November difference, not shown on the graph, is 2.6 Bcf/d).

We have studied Texas production reporting and find that it is generally reliable and accurate in areas that we follow closely in our oil and gas exploration and production business. Revisions are common for the first and second most recent months of production but are not statistically significant at the state or field level. Data going back three reporting months is reliable. Studies of other major gas-producing states show similar results. Our intent to is to point out the differences between state and EIA data, and to suggest that EIA data is not particularly useful to track individual play or some state production on a current basis.

Texas, Louisiana, Wyoming, Oklahoma, Gulf of Mexico Outer Continental Shelf, and New Mexico account for roughly 75% of U.S. natural gas supply and, therefore, provide a useful proxy for total U.S gas production. Exhibits 12 through 17 show natural gas production for these regions.

All of these major gas-producing areas except Louisiana are in decline. This is largely because non-shale production is declining rapidly since little new drilling in these reservoirs in recent years has occurred. While shale production volumes and initial rates are impressive (Exhibit 18), much of this new production is merely substituting for depleting conventional gas reserves.

With the shift to more oil-prone or “liquids-rich” shale plays, many observers have suggested that associated gas production from these plays is or will be a major contributor to the present over-supply of gas. Approximately 3% of total U.S. gas supply is from shale associated gas so, while this is a factor, it is not the cause of over-supply. Details of this analysis may be found in an earlier post. Overall, U.S. natural gas production using state-level data appears to have reached an undulating plateau (Exhibit 19).

Conclusions

A secular shift has occurred in the U.S. domestic gas supply by drilling mostly shale formations, formerly considered source rocks too costly to develop. The tremendous number of wells drilled in the last several years has contributed to an over-supply of gas. The shale revolution did not begin because producing oil and gas from shale was a good idea but because more attractive opportunities were largely exhausted. Initial production rates from shale are high but expensive drilling and completion costs make economics challenging. The gold rush mentality taken by companies to enter shale plays has added expensive leases and new pipelines to those costs, further complicating shale gas economics.

In the decades before shale plays, the exploration and production emphasis was on discipline. Science was used to identify the most prospective areas in order to limit the amount of acreage to be acquired and its cost. Shale plays have produced a land grab business model in which hundreds of thousands of acres are acquired by each company. Unprecedented lease costs have become the norm often based on limited information and science.

Operators have indulged in over-drilling these plays for many reasons but adding reserves, holding leases and company growth are among the main factors particularly with the low cost of capital. The inevitable result has been the collapse of prices as supply exceeded demand. Most analysts forecast that the future will be much like the present, and that natural gas will be abundant and cheap for decades to come. There are, however, strong and consistent indicators that natural gas supply may be less certain than most observers believe and require a higher price to be developed economically. Natural gas demand is growing as fuel switching for electric power generation continues, and will be increased by environmental regulation in the coming years. The U.S. will shift more of its future energy needs to natural gas in many sectors of the economy. The best justification, in fact, for the land grab and over-drilling spree is expectation of higher prices. Those companies that grabbed the land and held it by production will profit greatly once the true supply and cost of shale gas is recognized.

The financial survival of all companies in this position is not, however, certain. Price matters, and there is finally some response from shale gas producers with recent announcements to curtail drilling. While price was cited as the main reason for reduced drilling, it is likely that some companies now have financial constraints. The shale gas phenomenon has been funded mostly by debt and equity offerings. At this point, further debt and share dilution are less feasible for many companies. Joint ventures have provided a way for some to prolong spending but that now seems like a less likely source of funding. Capital availability in the near term will likely be tighter than is has until now. Acquisition and consolidation may become more attractive to companies with cash as producers become more extended.

Some of the shale gas plays may be at or near peak production at least at the current price of gas and technology. All major producing areas except Louisiana are in decline. Some doubt the accuracy of public data compared with EIA data, but it seems unlikely that the trends it shows are erroneous. In any case, the data the EIA makes available does not have sufficient resolution to evaluate individual plays or state-level trends.

Intermediate-term shale well performance is poorer than assumed previously. Continuous treadmill drilling masks this issue so play decline rates are not recognized. High decline rates are, however, a salient issue meaning that and most of a shale gas well’s reserve is produced in the first few years. Well life appears to be shorter than initial expectations. This means that an increasing number of wells must be drilled in order to maintain supply. Now, it appears that fewer wells may be drilled until price recovers to commercial levels. The argument for improved efficiency that cites increasing production with lower rig count is suspect. It is mostly because of the large backlog of previously drilled wells that are just now being connected to sales. This spare capacity provides a boost to supply during a period of falling gas-directed rig count.

The gold rush is over at least for now for the less commercial shale plays. The money and activity have moved to more oil-prone shale plays such as the Eagle Ford and Bakken or to higher potential gas plays such as the Marcellus. Improbable stories that great profits can be made at increasingly lower prices have intersected with reality. A painful adjustment is underway in the natural gas exploration and production industry. Fewer jobs will be created and projects may develop more slowly. This development may expose the notion of long-term natural gas abundance and cheap gas as an illusion. The good news is that this adjustment will lead to higher gas prices in a future less distant than most believe. Higher prices coupled with greater discipline in drilling will allow operators to earn a suitable return and offer the best opportunity for supply to grow to meet future needs.

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In last week’s State of the Union address, President Obama called for an all-of-the-above approach to energy as a critical part of securing this country’s future – and we agree. The United States must pursue all of its energy options – including increased domestic oil and natural gas production, coal, nuclear, renewables and more.

That includes unconventional energy sources. Certainly, the United States is realizing almost unimaginable growth in the development of oil and natural gas from shale, which is powering an economic boom in North Dakota, Pennsylvania, Texas and others.

Just a few years ago, that hardly seemed likely. Yet, the latest data from the Energy Information Administration demonstrates how technological advances in hydraulic fracturing and horizontal drilling have dramatically increased America’s natural gas potential to the point that the EIA now says the U.S. is home to the second-largest natural gas reserves in the world, and that by 2035, 70 percent of the country’s gas supply will be produced by fracking from shale and tight rock formations.

Let’s talk about another unconventional energy source: oil shale, which will be discussed this week by the House Natural Resources Committee as it considers legislation to promote access to U.S. resources. By all accounts this resource base is enormous. The largest and highest quality oil shale deposits are in sparsely populated areas of Colorado, Utah and Wyoming, and the potentially recoverable oil from Western U.S. oil shale deposits is estimated at more than 800 billion barrels, or nearly three times the proven oil reserves of Saudi Arabia (267 billion). In its September 2011 report on North American resources, the National Petroleum Council notes that given the right technological advances, the potential of oil shale could be significant in terms of energy and jobs.

Easily confused with oil that is extracted by fracturing shale formations to released trapped oil, oil shale is a fine-grained sedimentary rock containing a solid material (kerogen) that converts to liquid oil when heated. Historically, oil shale has proven to be technically, environmentally and economically challenging to develop. However, through ongoing research efforts, new and innovative production oil shale technologies are emerging. Today several dozen technology and resource development companies are working on the next generation of oil shale technologies. Companies have shown they can extract oil shale with minimal surface disturbance, followed by programs to restore the environment to its natural state.

Several technologies have been developed around the world to make oil shale commercially viable in countries including Brazil, China and Estonia. With the United States holding nearly three times the proven oil reserves of Saudi Arabia in shale oil, we need the right policies to set the stage for commercial viability.

Some argue oil shale shouldn’t be pursued as a resource, claiming it will never be commercially viable – apparently unaware of its commercial success in other countries. If anything, the energy from shale revolution in this country as well as the continued development of alternative and renewable energy sources suggest no potential resource should be dismissed because of its current commercial viability.

The president is right: an all-of-the-above approach is the best path for securing America’s energy future. In oil shale, the United States has another vast energy resource that can’t be dismissed – one that would be best developed by industry and the marketplace, guided by clear policies and a stable regulatory regime.

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Proposed new deep-water leases off the coast of Louisiana, Mississippi and Alabama could yield 1 billion barrels of oil and 4 trillion cubic feet of natural gas, according to the Obama administration, announcing a June 20 lease sale in New Orelans.

The sale will include all available unleased areas in the Central Planning Area offshore Louisiana, Mississippi and Alabama. Minimum bids for the deepwater leases will be set at $100 per acre, administration officials said, after an economic analysis showed that leases sold for less than that amount saw virtually no exploration and development drilling during the past 15 years.

Conservation groups have been critical of new lease sales in the Gulf, pointing out that some areas that have already been leased haven’t been explored yet. There are lingering concerns that the administration hasn’t done nearly enough to protect the environment in the wake of the Deepwater Horizon disaster, which marred the Gulf with 5 million gallons of crude oil spreading across nearly 4,000 square miles of the Gulf — the largest oil spill ever.

The Deepwater disaster resulted in extensive damagle to marine and coastal ecosystems, as well as to the Gulf Coast fishing and tourism industries, eventually affected about 320 miles of coastline in Louisiana alone. Six months after the spill, some reports of tar balls along beaches continue, along with visible oil sheen trails in some areas. In other areas, deposits of crude on the seafloor are apparently not degrading and marine mammal mortality in the Gulf remains above normal.

But there is also enormous economic and political pressure to push ahead with more deep sea drilling, and it is, of course, an election year.

The proposed lease sale includes approximately 7,250 unleased blocks covering nearly 38 million acres. The blocks are located from three to about 230 miles offshore, in water depths ranging from 9,000 to more than 11,115 feet (three to 3,400 meters) in the Central Gulf of Mexico, a region that BOEM estimates contains close to 31 billion barrels of oil and 134 trillion cubic feet of natural gas that are currently undiscovered and technically recoverable.

“Expanding offshore oil and gas production is a key component of our comprehensive energy strategy to grow America’s energy economy, and will help us continue to reduce our dependence on foreign oil and create jobs here at home,” said Secretary of the Interior Ken Salazar. “The President has made it clear that developing our domestic oil and gas resources is a significant part of this administration’s efforts to grow our economy and create jobs. This lease sale is part of our commitment to safe and responsible development of the Outer Continental Shelf.”

The June 20 sale is the last in the series of sales in the five-year 2007-2012 outer continental shelf leasing program,

“The Central Gulf of Mexico remains the area with the greatest offshore oil and gas potential in the entire United States outer continental shelf, and this proposed sale is another important step in making this area available for safe and environmentally responsible exploration and development,” said Director Tommy P. Beaudreau. “We are moving forward with this sale based on careful analysis of the best scientific information available and consideration of all of the public comments we have received.”

The terms and conditions of the sale are online here and the Federal Register notice is online here.

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The administration recently announced a seven-year ban on drilling in the eastern Gulf of Mexico, as well as along the Pacific and Atlantic coastlines, citing the BP oil spill as the reason.

But though the announcement is a virtual flip-flop of what the administration made known earlier this year, Dan Kish, senior vice president of policy at the Institute for Energy Research (IER), says the administration’s decision is par for the course in terms of its energy policies.

Dan Kish (Inst. for Energy Research)”It’s thoroughly consistent with this administration’s approach toward domestic production of energy, which is to make it harder,” Kish suggests. “And the result is going to be we’re going to import more oil and have people working in other countries.”

He goes on to report that IER president Tom Pyle has issued a statement saying: “It is now abundantly clear the administration and Interior Secretary Ken Salazar will stop at nothing — lost jobs, tax revenue, or a threat to national security — to enforce their vendetta against domestic energy production. Despite promises made to Senator [Mary] Landrieu (D-Louisiana) and the thousands whose livelihood depends on energy development, they continue to pursue an ‘all or nothing’ approach to alternative energy that will do nothing more than weaken our economy, increase our dependence on foreign oil, and eliminate thousands of well-paying, secure American jobs.”

Meanwhile, Myron Ebell of the Competitive Enterprise Institute has made similar claims, adding that “President Obama is dishonestly pursuing policies that are the opposite of what he promised and that are against America’s economic interests and opposed by a strong majority of Americans.”

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There has been a significant amount of mergers and acquisitions (M&A) activity over the past several months in the natural gas industry. The most recent of these was the purchase of independent natural producer Atlas Energy, Inc. by integrated oil giant, Chevron (CVX). The former agreed to be bought out for $4.3 billion in a combination of cash and stock. Under the terms of the deal, shareholders of Atlas will receive upon consummation $43.34 per share, which is a 37% premium over the closing price of the stock the day prior to the deal’s announcement.

This acquisition follows in the wake of similar transactions that have occurred recently. Operators such as Statoil (STO), BP, Total (TOT), and Royal Dutch Shell (RDS.A) have all announced purchases of US shale assets in recent months. Exxon Mobil Corporation (XOM) was the first mover in the consolidation wave about a year ago when it announced the buyout of XTO Energy. That acquisition thrust Exxon Mobil into the position of largest natural gas company in the US.

The interesting point about this round of M&A activity is the timing. It is occurring at a point when the supply of natural gas is abundant and prices are correspondingly depressed. In fact, natural gas prices remain firmly below pre-economic crisis levels. Much of the reasoning for the price slump can be attributed to prolific gas discoveries in previously inaccessible geological structures, such as Haynesville, Marcellus and Eagle Ford Shale Formations. Couple this with the advent of new technologies to access these unconventional deposits and the result is the surplus of the commodity. According to US Energy Department estimates, the Marcellus Shale alone is thought to hold somewhere in the vicinity of 262 trillion cubic feet of natural gas. This massive geological formation is the largest gas field in the US and touches four states: Pennsylvania, New York, West Virginia and Ohio.

The fundamental profile for the natural gas industry is not very compelling at this juncture. Operating costs are rising, but the commodity’s price remains subdued. While there has been a flood of speculative capital flowing into the sector over the last two years or so, these funds are almost depleted. It is unlikely that a fresh round of financing will be forthcoming due to the low return on capital to date. The depressed price of gas and poor visibility for significant profitability has weighed on the equity valuations of the companies with a presence in the market. This is particularly true for independent operators with significant acreage under their control, but limited balance sheet capacity to ride out the cycle. It stands to reason that these operators are increasingly likely to become targets of the larger integrated companies that have stronger financial capabilities.

The managements of these larger majors have recognized the potential of natural gas over the long term. Natural gas prices are cyclical and would eventually rise. To that point, the decision by Chevron’s management and its peers to acquire assets at low valuation can be considered to be prescient. As such, the environment is fertile for additional M&A activity over the next several months.

The fact that there could be a scaling back in drilling activity for gas in the not too distant future could prove to be an upside catalyst for natural gas prices. As such, the stocks of those companies with solid balance sheets and sizable acreage could move meaningfully higher.

Tue Nov 9, 2010 5:46pm GMT

* EIA sees 2010 US gas output up 1.51 bcfd from 2009

* 2011 production forecast is for a drop of 1.2 pct

* Henry Hub 2010 cash prices expected up 10 pct at $4.35 (Adds background, LNG outlook, Henry Hub price estimates)

NEW YORK, Nov 9 (Reuters) – The U.S. Energy Information Administration on Tuesday slightly raised its estimate for domestic natural gas production in 2010, expecting total output this year to be up 2.5 percent from 2009 levels.

In its November Short-Term Energy Outlook, EIA said it expected marketed natural gas production to be up 1.51 billion cubic feet per day in 2010 to 61.49 bcf.

That estimate was revised up slightly from EIA’s October outlook that had production in 2010 growing 2.2 percent to 61.29 bcf daily.

In 2011, EIA expects marketed gas production to slip 1.2 percent to 60.77 bcf per day, primarily due to a sharp decline in offshore Gulf of Mexico gas output.

EIA lowered its forecast for U.S. natural gas consumption this year, expecting demand to average about 65.00 bcf per day, up 4.3 percent from 2009 demand of 62.30 bcf daily.

The agency previously expected consumption to be up 4.6 percent in 2010.

EIA said the bulk of the 2010 increase in demand was due to strong growth in the power generation and industrial sectors. Hot summer weather and relatively low natural gas prices drove power sector demand up by about 7.6 percent this year.

In 2011, total gas demand was expected to climb another 0.6 percent, up from EIA’s previous estimate of about flat.

Regarding liquefied natural gas, EIA expects LNG imports to fall to 1.23 billion cubic feet per day this year, a very slight decline from 2009 levels, as increased domestic production and low U.S. gas prices discourage imports.

EIA expects LNG imports to rebound in 2011 to 1.32 bcfd, a 7 percent increase.

EIA also expects Henry Hub natural gas prices this year to rise 10 percent from 2009 to about $4.35 per million British thermal units, with 2011 prices expected to slip slightly to about $4.31 based on upward revisions for domestic production and inventory forecasts.

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THE US Energy Information Administration (EIA) said yesterday it would not change its forecast for offshore oil production cuts after Tuesday’s lifting of a deep-water drilling ban.

The EIA predicted the deep-water moratorium, imposed in response to the BP oil spill in the Gulf of Mexico, would cut US offshore oil production by 31000 barrels a day in the fourth quarter and by 82000 barrels a day next year, Richard Newell, the agency’s administrator, said.

“We’re not expecting that to change significantly as a result of the announcement yesterday,” he said.

US Interior Secretary Ken Salazar on Tuesday lifted the ban on deep-water drilling to deeper than 152m, citing new safeguards intended to prevent a repeat of the Gulf of Mexico spill. The moratorium was opposed by officials in Gulf Coast states, who said it only added to the economic effects of the spill.
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WASHINGTON, Oct 13 (Reuters) – The Obama administration’s decision to end the deepwater drilling moratorium early will not have a major impact on U.S. oil production in the Gulf of Mexico, the head of the government’s energy forecasting arm said on Wednesday.

The drilling ban was ended by the Interior Department this week, but tough new safety rules will likely delay any new drilling permits from being issued until near the end of this year.

“At this point we’re expecting it’s kind of a wash,” Richard Newell, head of the Energy Information Administration, said at the agency’s winter fuel outlook forum.

The agency does not currently plan to make any major revisions to its previous forecast that the temporary drilling ban would cut Gulf oil output by an average of about 82,000 barrels per day next year.

Even though the ban was lifted early, “We think it’s still going to take some time for companies to get permits from the Department of the Interior,” Newell said.

The department’s drilling freeze had been expected to end at the end of November, but Interior said new rules had significantly improved the safety of drilling since the BP (BP.L) oil spill ravaged the Gulf.

In its new monthly energy forecast, the EIA said U.S. oil production from the Gulf was expected to drop next year by 170,000 bpd, about 50,000 bpd more than the agency forecast last month.

Newell said the adjustment to the forecast was not based on any changes in the agency’s assumptions about the drilling ban.

Due to the lag in time between drilling for oil and oil production, Newell said, it could take two years for Gulf production to return to levels reached prior to the drilling ban. (additional reporting by Tom Doggett; Editing by Walter Bagley)

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