While much of the world is concerned about whether Saudi Arabia can deliver on its promise to produce an extra 1 million barrels of oil a day, far more attention should be given to OPEC and non-OPEC member countries whose production continues to fall. Oman and Indonesia are two such countries whose continued production declines will more than offset production increases from Saudi Arabia or anywhere else in the world. In this month’s issue, we review the current state of oil production in Oman and Indonesia and what it tells us about fellow oil exporting countries. (It should be noted that Indonesia is a member of OPEC and Oman is not.)

While every country has a unique oil production decline curve, Oman’s struggle to maintain its oil production may shed some light on the future of its larger neighbor, Saudi Arabia. Petroleum Development Oman (PDO) is the country’s second-largest employer after the government. The company is a consortium comprised of the Omani government (60%), operator Shell (34%), Total (4%), and Partex (2%). It holds over 90% of the country’s oil reserves (proven reserves are 5.5 billion barrels of oil) and accounts for about 94% of production. In 2003, PDO’s crude oil production slipped to just over 700,000 barrels of oil per day (bbl/d), down from a high of almost 1 million bbl/d five years ago. PDO now aims to restore and stabilize output at 800,000 bbl/d by 2007. It hopes to achieve this goal by increasing recovery rates and by discovering and exploiting new fields, particularly in the south.

Due to PDO’s already extensive use of enhanced oil recovery (EOR) methods, the company faces an uphill battle to increase oil production from current levels. The most common EOR scheme employed by PDO is the use of maximum recovery contact (MRC) wells combined with water flooding. MRC wells are usually horizontal wells with multiple bores extending from a single site and designed, as the name implies, to maximize contact with the oil-bearing strata. Water flooding involves drilling water injection wells in a reservoir and pumping water into the field to push the oil towards the oil producing well bores.

Oman’s Yibal field, which began production in 1968, is an excellent example of a field that has responded nicely to MRC wells combined with water flooding. After many years of infill drilling and the use of water injection wells, PDO made the decision in 1994 to use horizontal wells. Today, the Yibal field contains nearly 500 horizontal wells, which helped the field reach peak production at more than 250,000 bbl/d in the late 1990’s. Horizontal drilling has led to a dramatic increase in water production and an equally impressive decline in oil production. In 2003, Yibal produced approximately 80,000 bbl/d and approximately 700,000 barrels of water per day. Such a high water cut speaks volumes about the maturity of the field and portends a field approaching the end of its productive life. It is estimated that PDO has already recovered approximately 42% of Yibal’s oil in place, although it hopes to get the field’s recovery factor close to 55%.

Why is Yibal important?

Yibal’s life cycle is important because many of the same EOR techniques used on the field have also been employed on the world’s largest oil field, Saudi Arabia’s Ghawar. In a February 2004 symposium at the Center for Strategic and International Studies in Washington, DC, energy investment banker Matt Simmons confronted two Saudi Aramco officials with the suggestion that the advanced recovery techniques used at Ghawar, which produces approximately 4.5 million bbl/d, have created an illusionary “fountain of youth” for the field. Simmons’ theory, which is based on the review of over 200 technical papers, suggests that the combination of horizontal drilling and water flooding has allowed Aramco to keep Ghawar production flat at the expense of future production. More importantly, Simmons believes that Ghawar’s rising water cuts indicate that the field is about to head into terminal and irreversible decline. Should Ghawar’s water cuts keep rising similar to Yibal’s; the world will soon experience triple digit oil prices.

Indonesia is one of the world’s oldest petroleum producing provinces and is likely to provide the blueprint of the future for several OPEC member countries. Indonesia has had a long history of oil production dating all the way back to 1884 when the Royal Dutch Company found oil on the island of Sumatra.

Due to political uncertainty, aging fields and lack of significant new discoveries, Indonesia’s oil production has been dropping for years. The country’s oil production averaged 1.02 million bbl/d in 2003 down from 1.10 million bbl/d in 2002. Production is expected to be down again in 2004. While many market observers complain about OPEC’s lack of discipline with some members habitually producing over their quotas, Indonesia consistently under produces its current quota of 1.22 million bbl/d and will continue to do so for the foreseeable future.

Indonesia’s Oil Production in Decline

It should be noted that Indonesia’s oil production continues to drop despite tremendous efforts put forth by the country’s operators. Caltex, which has the largest operation of any multinational oil company in Indonesia, began a $2US billion steam injection project at the Duri field on Sumatra in 1985 that is nearing completion. Even with the help of steam injections, the Duri field had average production of 204,000 bbl/d in 2003, a drop of 71,000 bbl/d from 2002 levels.

In an ironic twist of events, Japanese soldiers discovered the largest oil field ever found in Southeast Asia in 1944 when they drilled into the Minas field in Central Sumatra. After over 50 years of production, the Minas field currently produces about 109,000 bbl/d (down 36% from year 2000 levels) through the injection of nearly 7 million barrels of water a day into the field.

All hope is not lost for the future of oil production in Indonesia; the Cepu field in Java is expected to come online in 2006 with a potential maximum production rate of approximately 180,000 bbl/d. However, Cepu’s operator Exxon-Mobil and its partner PT Petromina (Indonesia’s state-run oil company) are at odds over the field’s development costs and production sharing.

While Indonesia’s oil production capacity continues to dwindle, the country’s natural gas production has remained flat. The US Department of Energy (DOE) estimates that Indonesia has reserves of 90.5 trillion cubic feet (tcf) and production of 2.5 tcf per year. Since the country consumes only 50% of its gas production per year, Indonesia has been able to maintain the title of the world’s leading exporter of liquefied natural gas (LNG). Japan, South Korea and Taiwan are the primary destinations for much of Indonesia’s LNG exports. Beginning in 2007, Indonesia will export 2.6 million tons of LNG a year to China.

Indonesia marks the first OPEC country to achieve a couple of significant milestones that will likely be repeated by other OPEC members. First, after more than 100 years of exporting oil, Indonesia became a net importer of oil in 2004. I believe the increased use of modern technology will deplete the reserves of smaller OPEC producers such as Libya and Qatar faster than many thought possible. This could make these countries net oil importers in the not too distant future.

Indonesia’s increased focus on natural gas exports to replace lost foreign exchange earnings due to reduced oil exports is also likely to be mimicked by other OPEC member countries. As several OPEC countries pass their peak oil producing years and oil becomes more expensive and difficult to extract, capital will be diverted away from oil production and into higher margin natural gas production and liquefaction facilities.

In conclusion, we have seen that when smaller oil producing countries employ advanced technology to maximize production, they eventually experience production declines at an accelerated rate. Will larger producers experience a similar fate? Evidence points strongly in that direction; although larger producers may be able to ride the production treadmill a bit longer. One thing is certain, when the world’s largest producers begin experiencing production declines, oil prices will head to previously unimagined levels.

Oil and NG Market Update

For many trading sessions we have seen the price of natural gas hover around $6.00US per thousand cubic feet (mcf). Recent price stability for one of the world’s most volatile commodities has allowed market participants to extrapolate recent prices into future months. I believe the short term thinking of many of today’s NYMEX futures traders is about to leave many of them sitting on the sidelines or short natural gas futures at the worst possible time, now!

There is growing evidence to suggest that natural gas prices are about to move into the $8-10US range in the very near future. Despite ending the winter heating season with a substantial surplus over last year’s low levels of storage, US natural gas inventories are returning to last year’s levels. The below passage was taken from a recent Lehman Brother’s report published in early July:

“Over the past 8 weeks weather normalized injections have been averaging about 3.9 billion cubic feet per day (bcfpd) below last year’s level. If this were to continue over the remainder of the refill season, storage would reach only 2,850 billion cubic feet (bcf) by the end of October. For storage to reach our targeted 3,100 bcf by the end of October, we need to see storage injections average 1.8 bcfpd less than last year for the remaining 17 weeks. This implies that supply needs to climb and/or the market needs to shed about 2 bcfpd of demand. This indicates continued strong gas prices over the remainder of the injection season.”

Another component of US gas supply comes from the north – and the story does not bode well for weaker prices. According to the US DOE, natural gas imports from Canada have declined 1% in the first four months of 2004 versus the same period a year ago. Canada’s decline in natural gas exports is due to increased internal consumption and flat production in the early part of the year.

Probably the most damning piece of evidence that we are heading for a higher natural gas trading range is the state of US production. According to a Raymond James review of Q1 production figures from publicly traded companies, US natural gas production fell 4.2% on a year-over-year basis and .5% on a sequential basis. Raymond James has been using the same methodology for tallying US natural gas production for several years and I believe their figures to be among the most accurate available from any source. The fact that US natural gas production fell during Q1 at a time of near record prices underscores the steepness of the US decline curve.

On July 14th, crude oil prices crept over $41US on news that US crude inventories fell 2.1 million barrels in the previous week and reports that tankers refused to dock at the Iraqi port of Basra due to security concerns. With refineries running near full capacity and home heating oil prices remaining near historic highs, the upcoming winter heating season should see record prices for both crude and refined products. Do not be surprised to see crude prices break the $50 a barrel barrier before the end of next winter.

Bolivia Revisited

The November 2003 issue of the Canadian Energy Viewpoint contained an article entitled “Why Bolivia is Important” that discussed the bitter battle over control of Bolivia’s massive natural gas reserves and how it led to the country’s President resigning from office. Control of the country’s natural gas resource is back in the news. To put the size of this country’s reserves into perspective, an April 2003 study by US reserve consulting firm DeGolyer & MacNaughton placed the country’s proved plus probable reserves at 54.9 tcf — well over two times US annual consumption.

Bolivia’s new leader, President Carlos Mesa, is well aware of the firestorm unleashed in 2003 when his predecessor supported the decision to build a natural gas export pipeline through Chile to the Pacific coast to allow for LNG export to the US. Mesa decided to let the country’s citizens decide the fate of the country’s natural gas.

Many of the country’s European descended elites fall into the pro-export camp since they believe the foreign reserve earnings the country will generate through the sale of natural gas exports will increase the quality of life for all the country’s citizens. The country’s Indian majority conversely believes that like silver in Spanish colonial times, exporting this latest natural resource will lead to their enslavement. They oppose exporting gas when 80% of Bolivia’s eight million inhabitants live in poverty with no running water or electricity.

On Sunday July 18th, voters went to the polls to decide whether gas exports should be allowed and whether the government should have control over the country’s natural gas assets.

The five questions that made up the referendum allowed for many interpretations of how Bolivia’s oil and gas industry will change as a result of the vote. While voters cast their ballots in favor of continued exports (Bolivia currently exports gas to Brazil), they also passed a resolution that will raise royalties and taxes on raw gas production from 34% to at least 50% of the value of the gas. Also, Bolivia’s President Carlos Mesa will present the country’s congress with a bill that will most likely give the government substantially more control over the country’s oil and gas industry.

While the recent referendum did not prohibit natural gas exports from Bolivia, it sent a clear message to those interested in exporting Bolivia’s gas to the US and Mexico that the country is not going to accept anything less than onerous terms for the right to develop one of its most precious natural resources.