Drilling

According to several sources, the U.S. House of Representatives plans to vote on the American Clean Energy & Security Act this week.  Key provisions of the bill encompass a reduction in greenhouse gases by 17% from 2005 levels within the next decade (to 2020). The bill also calls for a 15% nationwide renewable electricity standard by 2020.  Representative Waxman, the bill’s author, has been forced to make some last minute concessions to farm state Democrats to allow a vote on the bill.  If passed on Friday, the U.S. Senate would then take up consideration of the bill.  The Obama Administration has announced that it would prefer to have a bill passed and signed into law before the next major UN climate conference in Copenhagen in December 2009, according to the Simmons Morning Report for June 24.

On Tuesday, May 5, 2009, a luncheon was held at Houston’s Hotel Za Za celebrating the renewal of the Bilateral Partnership for Business Growth and Cooperation between Houston, Texas, and Calgary, Alberta, Canada. The main message of the event was Calgary Mayor Dave Bronconnier’s urge for energy centers like Houston and Calgary to become leaders in reducing green house gas emissions. Bronconnier said, “Cities like ours have the most to lose and the most to gain.”

“There are few cities better positioned than Calgary and Houston to actually deliver on this goal. We have the corporate infrastructure, the people and the know how to spear-head the development and commercialization of green energy technology,” said Bronconnier.

“There is no doubt that green house gas emissions have become one of our most pressing issues.

“But if we are willing to be engaged in that discussion, and to continue to show our leadership through the actions of our people, governments and industry, I have no doubt we have the most to gain from the future,” said Bronconnier.

The lunch was hosted by the Greater Houston Partnership in Texas, and applauded the leadership of Mayor Bill White.

Uruguay’s government kicked its first ever offshore bidding round in December 2008. Now with lower prices and financial uncertainty affecting potential suitors for its offshore licenses, the country has changed some of its original rules to keep interested parties attentive.

The Uruguayan national oil company, ANCAP, has monitored the industry since the bid round was announced in December. As a result of drop in price and shrinking or suspended exploration budgets among the world’s operators, ANCAP is recommending relevant modifications to the bidding bases and contract model of the Uruguay Round 2009.

Due to proposals by ANCAP, the mandatory fulfillment for an exploration well during the basic exploratory period for A-classified blocks has been removed. Companies will not be restricted from including them in program offers. The contract guarantee percentage for the first basic exploratory period will be adjusted from 5% to 10% of the minimum exploratory program value for the A-classified blocks. Basically, this will give all Uruguayan blocks (A and B) the same requisites for guarantees and minimum exploratory program.

The Uruguayan government signed its new decree on March 30, 2009. It hopes that the change will be viewed as an example of its capacity to adapt easily and timely to the current economic reality as it pertains to the upstream sector. The Uruguayan government considers the country to now have some of the best conditions for exploration investments.

As it is, licenses will continue to be awarded on a production-sharing agreement only. The 11 blocks on offer are in the Punta del Este and Pelotas Basins, and the Oriental del Plata further offshore. Available blocks range from 965 to 3,861 sq miles (2,500 to 10,000 sq km) in size. Water depths range from 164 to 4,922 ft (50 to 1,500 m).

ANCAP’s technicians used a series of 2-D seismic data acquired by Wavefield Inseis ASA to establish a number of bright spots and possible plays in the region. Uruguay’s government announced in 2008 that it had identified more than a dozen prospective offshore natural gas areas, each of which could boast between 1 Tcf and 3 Tcf of gas, although a spokesman for ANCAP cautioned that it would be very premature to estimate reserves.

Currently, no companies work offshore Uruguay and there are no producing fields either on or offshore. In the current economic climate, the country will be hard pressed to attract investment to an untapped prospect with unproven reserves.

At present, no companies are working in Uruguay’s upstream oil and gas sector, but two small companies (one from US and one from Australia) have applied to get an onshore prospection license, ANCAP’s spokesman said. The due date for Uruguay’s bid round is held at July 1, 2009. Visit www.rondauruguay.gub.uy for more information on available acreage.

Economic times are shaky. Joe Biden, U.S. Vice President says, “It’s going to get worse before it gets better.” Really? I wasn’t sure. It’s no secret and many of us in the oil and gas industry are aware that business is getting tighter. Companies are scaling back and budgets are being reviewed to find ways to survive that uncertain time ahead. Apparently, Petrobras didn’t get the memo.

Brazil’s state-owned Petrobras released its 2009-2013 business plan on Friday. The company’s board of directors approved the plan which calls for US $174.4 billion in investment, which is $62 billion more than the company’s previous plan. The majority of the spending – $104.6 billion – will be focused on E&P efforts. The remainder will go for downstream ($43.3 billion), gas and energy ($11.8 billion), petrochemicals ($5.6 billion), distribution $3.2 billion, and biofuels ($2.8 billion).

In 2009, the company plans to invest $28.6 billion, a number that is based on the company’s strategic position laid out in the 2020 strategic plan. The 2009-2013 plan maintains aggressive growth goals and incorporates the company’s resources at exploring and developing recent oil discoveries made in the pre-salt cluster. Production goals in Brazil are 2.68 million b/d in 2013, 3.34 million b/d in 2015, and 3.92 million b/d in 2020.

Currently, the Tupi pilot system is scheduled to go on stream in 2010. In addition, three other systems are expected come online in the Santos Basin’s pre-salt area: the Tupi and Guara 1 in 2012 and the Iara 1 in 2013. In addition to domestic production, Petrobras expects its international production to increase to 341,000 boe/d in 2013. Total production is expected to reach 3.65 million b/d.

The company stated in its report that it would invest an average of $34.9 billion per year with 90% being spent in Brazil and the remaining 10% ($16.8 billion) invested abroad. Compared to the company’s previous plan (2008 – 2012), the E&P investment was increased by 71%. Total E&P spending is expected to reach $92 billion, or 53% of the current $174.4 billion approved for the 2009 – 2013 period.

The company will make a significant effort to assess and develop its pre-salt discoveries over the next four years. The company’s 2013 pre-salt oil production target has been set at 219,000 b/d in 2013. By 2015, the operator hopes to reach 582,000 b/d. Natural gas production is expected to be commercial in 2013 with production at 7 MMcf/d. By 2020, Petrobras targets oil and gas production to be at 1.82 million b/d and 40 MMcf/d respectively. With an average Brent price of $37 in 2009, the company is charged with raising an additional $18.1 billion in funding to meet its $28.6 billion goal. However, it has already secured the majority of this amount from BNDES and other sources.

In this economic climate it’s relieving to see an operator with conviction. Boom and bust cycles are not new to the oil business, and investing in future prospects serves as a reminder that the business always bounces back.

It’s not what you think. Although Israel is mentioned often in the main stream press, rarely is the news related to a burgeoning offshore industry – much less in the growing deepwater subsalt sector. Noble Energy has had more than a decade of experiencing operating in the Mediterranean Sea, offshore Israel. The company holds a 47% working interest in the Mari-D, one of its key international assets. Mari-B was the first offshore natural gas production facility. In 2007, gross field deliverability was 600 MMcf/d from six wells.

As early as 2004, the company began selling gas to the Israeli Electric Corp. and has steadily increased as Israel’s natural gas infrastructure continues developed. In addition to producing gas for onshore use in Israel, the company has continued its exploration efforts as well. As of December 2007, Noble Energy held 123,552 gross developed acres and 1.18 million gross undeveloped acres.

The company has discovered more natural gas at the Tamar prospect in the Matan license. The Tamar #1 well lies in 5,500 ft of water. It was drilled to a total depth of 16,076 ft to test a subsalt, lower-Miocene structure in the Levantine Basin. Formation logs identified approximately 460 ft of net pay in three high-quality reservoirs. The company reported the reservoirs encountered were greater than anticipated at the well. This was Noble’s first offshore well in Israel in five years. And, according to CEO Charles D. Davidson, is one of the largest discoveries in the company’s history. Early indications for the well show an estimate of more than 3 Tcf of natural gas.

The Tamar well will undergo further testing after it is completed and Noble Energy and its partners may drill up to two additional wells in the basin. Noble operates the well with a 36% working interest. Its partners include Isramco Negev 2 (28.75%), Delek Drilling (15.625%), Avner Oil Exploration (15.625%), and Dor Gas Exploration (4%).

Consultants Friedman, Billings, Ramsey & Co., Inc. (FBR) estimates the net value of the discovery at approximately US $750 million. This find is also right on the hills of Noble’s Gunflint discovery in, which is also a subsalt prospect in the U.S. Gulf of Mexico (GoM) announced in mid-October 2008. Commenting on the subsalt potential for today’s oil and gas market, FBR said the Israeli success bodes well for the E&P investment thesis of ongoing and underappreciated international exploration. “Armed with new 3-D technology and better analytical tools, there is an international exploration renaissance taking place areas like Brazil, Israel, Ghana, Equatorial Guinea, Sierra Leon, and so on.”

According to FBR, companies with material exposure to deepwater sub-salt exploration potential are typical favorites for investors in the energy industry. While prices continue to fluctuate, it’s a good sign that many operators are moving forward into deeper water searching for unconventional resources.

Now that everyone has settled back into their seats after the holidays, it is important to spend some time reflecting on the year that has passed while determining its implications for the year ahead.

Of course, 2008 was hectic and can hardly be summed up as business as usual. From a normal start to a raucous rise in mid-summer, the oil and gas business soared through the first half of the year. By November, we were looking at possible collapse. From best to worst case scenarios, a third party perspective can be helpful to delineate exactly what went on during 2008, and how it will most likely play out in 2009.

Lucky for us (or me I should say), Allen Brooks, Managing Director of Parks, Paton, Hoepfl & Brown Energy Investment Banking LP, has put together a common thread of the financial developments that took place during the year. Published as “Musings from the Oilpatch,” the document provides a decent narrative for the preconditions of the housing market crisis and its links to stock market that inevitably had a grand effect on the energy industry over the Q3 and Q4 of 2008.

In addition, it provides a general outlook for the coming year that’s as gloomy as the evening news wants you to believe. Most importantly, Brooks points out that oil prices will most likely trade at $50 to $60 per barrel with some excursions throughout 2009. Rig count is expected to drop 500 to 600 from yearend 2008.

The report states that oil and gas service company stocks should remain somewhat stable with time and possibly an upturn in the oil and gas prices providing a catalyst for recovery. It also points out that geology is the key factor for now. “It is our belief that the geology is the key factor that is different this time. The production depletion rate, which appears to be climbing, will be our long-term earnings and stock price driver. While it is hard to imagine now, just like last year at this time, 2009 is likely to be another surprising year!”

The full report is helpful in identifying the most important factors related to our current economic situation. To access Allen Brooks’ newsletter, which provides much more detail than I have hear visit www.pphb.com (See “Musings from the Oilpatch” January 6).

Today’s headlines are rife with bad news. Failing economies, rising unemployment, lower capital investments, and company bankruptcies are all on the hot list for journalists scrambling for news.

A recent report by consulting firm Ernst & Young is claiming that the “glass is half full.” The report points out, “The US oil and gas industry has experienced all of these, not just during the current financial crisis, but at many times during its 150-year history.” It also states that the industry has continuously proven its resilience in the face of adversity, whether it’s caused by downturns in supply and demand or outside forces beyond industry control. Recent market turmoil is unprecedented and, while it spells risk for some, opportunities abound for others.

The latest report titled “The Oil and Gas Industry and Financial Market Turmoil” speaks from a positive perspective on the industry’s current status. Namely, while the short-term demand for oil and gas is softening, the long-term demand continues to look modestly strong with a challenging long-term supply structure.

The world economy will continue to depend on the industry’s ability to find reliable sources of energy at economical prices. “Many oil and gas companies are currently very well capitalized and have large cash reserves, and thus will enjoy a liquidity advantage during a time of tighter credit,” the report said.

In 1901, Spindletop tripled US production and gave birth to the modern oil industry. Since that time, it has been characterized by booms and busts. “Near-term, in response to recent developments, companies need to focus on a back-to-basics approach to their operations and balance sheet,” the report said, adding, “Looking ahead, the financial crisis presents opportunities for well-capitalized companies to enter into acquisition transactions, from partnerships, find and nurture talent, grow their business in a more rational price climate and capitalize on opportunities for long-term hedging relationships.”

E&P companies should continue to invest with an attitude that “the glass is half full.” It would not only improve their own financial viability, but also the growth prospects of the entire world economy, the report added.

“The Oil and Gas Industry and Financial Market Turmoil” report was written by Marcela Donadio and Herb Listen, Ernst & Young LLC. A full version of this report can be located at www.ey.com/us/oilandgas.

Drilling makes the difference

How many times have you heard “we can’t drill our way to energy independence?” For many years now, legislators in the US have continually fought to prevent drilling operations from appearing in many of the country’s most prolific regions for natural resources like oil and gas – from onshore federal lands to offshore regions on the West, East, and Eastern Gulf Coasts.

The Energy Information Administration has published comprehensive US proved reserves data since 1977. The 2007 Annual Report of U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves (issued October 16, 2008) marks the thirty-first installment and shows record-high growth for dry natural gas and an addition to crude oil reserves for the first time in four years.

In 2007, the US recorded additions in proved reserves of dry natural gas – 46.1 Tcf, which is more than double than the amount of dry natural gas actually produced in 2007 (19.5 Tcf). The year-end total of proved reserves of dry natural gas in the US rose 13% above 2006 levels to 237.7 Tcf. This is the highest level in 31 years. Rapid development of unconventional resources such as coalbed methane and shale gas from tight, low permeability formations proved to add most of the additions.

The EIA estimates are based on a snapshot of what can be produced with reasonable certainty. Estimates can change as new discoveries and improving technologies increase. Changing prices can also alter estimates of proved reserves. If the reserves additions are greater than production, reserves increase, if they are less then estimates are reduced.

According to the report, 2007 was the ninth consecutive year that US natural gas proved reserves rose. The important point is that this year the rate of increase was more than twice as any year in the history of EIA data reporting. The proved reserves additions were developed through two broad categories: total discoveries (accounting for 63% or 29 Tcf of gas additions) and net revisions.

The report also noted additions to crude oil in the US for the first time in four years. Year end reserves for crude oil were 21.3 billion bbl, about 2% higher than at the end of 2006. Alaska saw the largest 2007 increase of 7% (284 million bbl) over 2006. This was followed closely by Texas with a 5% increase (251 million bbl) for the year. North Dakota, home to the Bakken formation, had the third largest increase of 70 million bbl of crude oil – up 17% from its 2006 reserves. Total discoveries of crude oil for 2007 in the US equaled 790 million bbl, which was 28% lower than the prior 10-year average (1.1 billion bbl) although it was 37% greater than in 2006 (577 million bbl). The majority of reserves additions to crude oil came form field extension operations however new field discoveries doubled in 2007 over 2006 (66 million bbl). Additionally, new reservoir discoveries in old fields were 70% higher in 2007 than in 2006.

This has been attributed to more aggressive drilling programs in many regions throughout the US. According to Baker Hughes, about 80% of the wells being drilled in the US have been for natural gas, which sheds light on the major increase in reserves.

Another hackneyed line you may be tired of hearing claims that the US contains 3% of the world’s reserves and consumes 25% of its resources. The EIA report shows the capacity for the US to up its reserves despite the fact that for 26 years approximately 85% of the country’s most vital lands have locked from exploration. With the offshore drilling ban now lifted it will be interesting to see how much increase will be shown in the EIA’s next Annual Report.

To see the full report visit http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/advanced_summary/current/adsum.pdf

According to a new White Paper published by 3i Oil, Gas & Power titled “Last Dash for Gas? Keeping Europe Out of Darkness”, an increase in gas-fired power generation is the only way of preventing a shortfall of capacity within the next ten years.

The report points out the possibilities of a reduction in generating capacity due to the boom-and-bust cyclical nature of developments. It supports the need for large-scale existing generation capacity replacement, and claims that, despite progress in some areas, renewable forms of power generation continue to have a limited impact on the overall market.

The paper also points out that with the implementation of certain initiatives such as low-emission generation (mostly nuclear), clean coal, and offshore wind at a utility scale could prevent an over reliance on gas fired production in the medium term.

3i’s paper states that all of these offer a range of challenges for developers, investors, and policy makers, but believes that with strong efforts to develop these programs across Europe, increased development of gas-fired generation can be sustained.

For a full view of 3i’s White Paper visit http://www.3i.com/publicationsandevents/the-last-dash-for-gas.html.

At a time when oil prices are at record highs, everyone scrambles for an easy solution. In the confusion many common sense observations become buried in the mass of “new” and “innovative” policy approaches that turn up on Capitol Hill.

On May 21, the United States House of Representatives approved legislation—324 for versus 84 against—that would allow the U.S. Justice Department to bring a lawsuit against OPEC members for allegedly adjusting the oil price by limiting its supply.

As of June 29, the Senate had yet to vote on the bill, according to Reuters. President Bush opposes the bill due to its potential to trigger retaliatory measures by OPEC members against American business interests. The White House has said it would veto the bill.

Republicans have argued that the law does not address the country’s energy problems. Rather than take legal action against sovereign nations, many skeptics of the bill have stated that Congress should instead clear the way for more domestic oil production in protected areas like the Arctic National Wildlife Refuge (ANWAR) in Alaska and some offshore waters that have been off limits to oil companies for more than 25 years.

Mirroring this assertion, Qatari Oil Minister Abdullah al-Attiyah said on Sunday, “The Congress should look to increase exploration inside the United States. It is strange to ask what I should produce. It’s an issue of sovereignty.”

In step with an attempt to bolster crude supplies in the U.S., the Bureau of Land Management (BLM) released the third phase of its 430-page jointly developed report, the Inventory of Onshore Federal Oil and Natural Gas Resources and Restrictions to Their Development. The inventory’s findings show that 60% of the onshore federal lands that have potential for domestic sources of natural gas and oil are currently closed to leasing due to special legislation.

The report claims that 62% of the nation’s oil and 41% of its natural gas is inaccessible for development. An additional 30% of onshore federal oil and 49% of onshore federal gas can be developed, but only after these operations are subjected to restrictions above the standard environmental lease terms including seasonal timing limitations. This leaves 8% of onshore federal oil and 10% of onshore federal gas to be developed under standard lease terms.

Several federal agencies manage parts of the 279 million acres inventoried, including the BLM, Department of Interior, and the U.S. Forest Service. An executive summary of the full report claims that undeveloped resources for these lands total 30.5 billion bbl of oil and 231 Tcf of gas. The total proved reserves for the land include 5.3 billion bbl of oil and 68.8 Tcf of gas.

With 60% of the land deemed inaccessible through legal restrictions, 19 billion bbl of oil and 94.5 Tcf are sequestered and out of reach of exploration efforts. An additional 9.3 billion bbl of oil and 112.9 Tcf are attainable through restrictions that are beyond standard stipulations. This leaves 2.3 billion bbl of oil and 23.6 Tcf of gas to be produced through standard lease terms.

If Congress is interested in lowering the country’s crude expenditure, it should seriously take a look at our own domestic inventory. We can’t place blame outside of the U.S. until we have exhausted every attempt to boost our own supply. We can’t have it both ways.