With today’s higher wellhead prices for crude and natural gas, governments of many producing countries are reexamining the fiscal terms of their production-sharing contracts (PSCs) in hopes of increasing their income.
Some of the most successful producing countries are responding to soaring prices by increasing the government’s take through taxes, royalties, and participation by national oil companies.
However, others that have been less successful in attracting foreign investors must decide whether to leave their tax take unaltered, make temporary changes, or introduce more-radical reform.
Some countries with more-mature producing areas where exploration fell off after the price collapse of 1998-99 are now offering incentives to encourage investment. Norway, for example, is trying to attract new entrants, while Indonesia and Australia are targeting frontier areas, said analysts at Wood Mackenzie Ltd. (WoodMac), Edinburgh, in an August report. On the other hand, Jim Mulva, chief executive of Conoco-Phillips in Houston, warned that the recently imposed UK tax hike could discourage future investment in North Sea oil operations.
Meanwhile, as the international natural gas market develops, many producing countries are turning to that as a new source of income and are likely to amend their PSCs to include terms for gas.
“I see action on almost all fronts,” said Daniel Johnston, an oil industry consultant and founder of Daniel Johnston & Co. Inc., Hancock, NH. “There are a lot of governments that are looking very closely at their systems because their take (as a percentage) went down with higher oil prices.”
Changing fiscal terms
Rising oil and gas prices and the release of prospective acreage have pushed up the government take in countries such as Egypt, Nigeria, and Kazakhstan.
“Most recently,” WoodMac reported, “investors were invited to bid profit shares rather than bonuses to acquire acreage in Algeria and Libya, and the resulting feeding frenzy ensures that the government take from future production on most of the licenses awarded will be very high indeed.”
Producing countries that don’t have “progressivity” provisions in their contract terms are most likely to embrace fiscal changes if current high crude prices are sustained, “particularly if the existing level of government take is relatively low,” at less than 50-60% of gross profits, said WoodMac analysts. “Whether these countries will respond with long-term changes or prefer temporary ad hoc changes will have a significant impact on the perceived risk associated with continued investment.”
WoodMac expects changes soon in fiscal terms for gas production in several countries where gas previously had little value. Increased demand for LNG in the US and Europe and higher North American spot prices for gas have improved the economics of international gas projects. Foreign investment rules of many producing counties offer no fiscal terms for gas development, and new terms must be negotiated within existing PSCs. WoodMac reports some increase already in the terms of new gas production contracts (e.g., Trinidad and Tobago). It expects future terms for gas to be more like those for oil.
“The apparent dearth of high-class exploration opportunities means the release of quality acreage will likely result in a highly competitive market,” said WoodMac analysts. “Recent experience in North Africa is likely to result in more countries using auctions based on profit share,” they said, “although others will prefer to fix the fiscal regime and maximize signature bonuses, as in West Africa and North America.”
PSCs
As international oil companies (IOCs) increasingly look outside of Organization for Economic Cooperation and Development member countries for new oil and gas resources, they face “a litany of fiscal regimes and contract structures,” including PSCs, said officials of Simmons & Co. International, Houston.
“Not all PSCs are created equal. Profit oil percentages can vary substantially from country to country,” said Simmons analysts. For example, under Iran’s “buyback” contract, they said, “Iran offers IOCs compensation for costs incurred developing the project through barrels produced from that project (similar to cost oil under a more traditional PSC).” It usually includes a 15-17% fixed return on investment in currency rather than a share of profit oil. “As a result, in a rising oil price environment, the total number of barrels required to pay out this return is reduced,” Simmons said. After costs are recovered, in as little as 5 years, operatorship is transferred to the host government, and the IOC holds no interest in the field.
A change in fiscal terms on a project in which an oil company has already sunk much or all of its upfront investment is certain to aggravate the investor. If terms are changed for future licenses or projects, at least the investor has the option of not participating.
Since oil prices began increasing from a 1999 low, said WoodMac analysts, “there have been relatively few increases in royalty or tax terms in the past 6 years that have applied to existing production. Russia and certain countries in Latin America have proved to be prone to most fiscal risk.” They noted a “global trend for governments to reduce corporate tax rates as part of broader fiscal policy, and over the review period a number of governments (e.g., Canada, Australia) have reduced general corporate tax rates, which are also payable by oil and gas producers.”
Although the WoodMac study was published in August, Richard Lines, head of petroleum economics for the company, said, “The emphasis is still the same.” The most significant change since the study was published is the 10% supplementary charge added to the UK taxation system. “What that effectively did is take the corporate income tax from 40% to 50%. That has had a really significant impact on the UK,” Lines said.
Meanwhile, most companies have fewer opportunities for investing their increased cash flow from higher commodity prices. A former trend of paying it back to shareholders “doesn’t seem to be happening quite as much,” said Lines. Mergers and acquisitions also have fallen off with crude wellhead prices in the $60/bbl range. The alternative is increased competition for exploration prospects and licenses.
“In time, opportunities become fewer and fewer, so basically you’ve got more companies with more money chasing fewer exploration opportunities,” Lines said. “That plays into the hands of governments as well and enables governments to be a little bit more selective with the fiscal terms that they choose.” Producing countries also must realize they’re now competing on a global stage and must provide the proper incentives to attract foreign investors.
IOCs are prepared to pay high taxes in order to invest in countries that have more and better prospects and that offer better potential returns on investment. However, they aren’t prepared to pay high taxes or big signature bonuses in countries that either don’t have an established track record or aren’t perceived to be prospective. Lines noted some “huge signature bonuses” paid in the last 5-10 years for concessions off Angola and for deepwater leases in the Gulf of Mexico where there’s a long history of successes.
However, he said, “Lesser known African countries like Kenya or Tanzania-there’s a long list of them-can’t demand high signature bonuses from companies because they don’t have that history of success, and they’re not perceived to be as prospective as other areas. They can’t change the prospectivity, but they can make it easier to invest by good marketing and access to information.”
Such countries may offer better terms under their PSCs, Lines said, such as the level of production sharing the companies get or the length of the exploration period. “They’ve got various things at their disposal, and certainly taxation is one of them.”
If oil prices fall to a lower level, he said, “I think you’ll probably see an overall decrease in terms of the host country’s ability to increase taxes. But that’s not particularly likely at the moment.”
Service agreements
Lines cited Iran and Venezuela as producers at the forefront in the use of service agreements to retain ownership of resources while pursuing international investment. “There really haven’t been any fundamental changes in terms offered by Iran,” he said. “If anything, [the companies] have just been squeezed a little bit. Under this structure, there is that the contactor has to commit to developing an asset for a specific value, and they have to keep developing costs within that budget. If they do so, they get a remuneration fee, which is basically a service for having done that work and committed that capital.”
Under a service agreement, the contractor absorbs cost overruns on projects. “And that is the real issue at the moment, because these contracts were signed a number of years ago in some cases,” Lines said. “Meanwhile, prices have been going up for the supplies of goods and services to develop assets. So the IOCs investing in Iran are having serious problems in trying to keep their costs under that budget.” Apart from that, he said, the general trend over the last 5 years or so within Iran is that the rates of return companies have been getting have dropped slightly, “turning the screws a little bit on the terms there.”
Petroleos de Venezuela SA has signed transitional agreements with several oil companies to convert their operating service agreements into joint ventures with the government. The government required companies that operate 32 oil fields in Venezuela to convert to joint ventures with PDVSA by the end of 2005. The IOCs want PDVSA to continue paying for their investments and expenses under the previous agreements until the national assembly approves the new JVs.
Under the former agreements, companies would sell their oil production to PDVSA at a discount to international crude prices and would be compensated for all of their operating expenses. The former agreements cost PDVSA an estimated $4 billion in 2005. The company said the new JVs should save $3 billion in operating costs this year.
WoodMac survey
Although Alaska increased the tax on Prudhoe Bay satellite fields, fiscal terms across North America were relatively stable in WoodMac’s 6-year review period published in late 2005. The US made minor changes to royalty relief in the deepwater Gulf of Mexico. “However, the government’s take remains among the lowest in the world, despite it being the most prolific and profitable province in the past decade,” said WoodMac analysts.
They reported a gradual decrease in Canada’s federal income tax rate, ultimately to only 21% in 2007. “Provincial royalty and income tax rates have been either stable or decreasing slightly,” WoodMac said, “and most provinces now have price-sensitive royalty rates, which will be automatically increasing the rate as prices increase.”
Latin America
WoodMac reported “some fiscal angst throughout Latin America over the past 5 years, notably in Venezuela.” Spurred by higher oil prices, Venezuela substantially increased royalty rates and the tax rate payable by marginal fields while reducing it on conventional production. “These changes in terms apply not only for new licenses but also to existing producers,” said WoodMac.
Argentina initially imposed an export tax on crude and then extended it to gas. In 2002, gas prices were converted to Argentine pesos from US dollars at a 1:1 rate, effectively a quarter of their previous value, although recovery is now under way.
Bolivia increased its royalty to a staggering 50% from 18%.
Brazilian investors face uncertainty over indirect taxes, although exemptions have been forthcoming.
In October, Trinidad and Tobago removed various allowances for both income tax and supplemental petroleum tax, applied retroactively to 2004 production.
Peru and Colombia are reducing royalties and state equity participation to stimulate exploration investment, and the government take in these two countries is now low by global standards.
Europe
Fiscal terms remained relatively stable in Europe. However, in 2002 the UK increased its tax rate to 40% (from 30%) for all new fields. To compensate, it abolished royalties on the oldest fields and accelerated depreciation for all new investment. But overall, the changes dampened investment, said WoodMac.
Norway, however, provided immediate tax deductions for exploration and appraisal drilling costs, creating a “unique situation where a newcomer that has an unsuccessful exploration program and exits will have only paid 22% of total costs, with the remainder picked up by the government,” said WoodMac.
Changes in the Danish regime in 2004 were sparked by renegotiation of the principal Dansk Undergrounds Consortium concession, which was to expire in 2012. In exchange for extending the contract to 2042, Denmark reduced hydrocarbon tax allowances as well as the rate-to 52% from 70%.
The Dutch fiscal regime has been modified several times, WoodMac said, mostly in favor of the investor.
Former Soviet countries
Investors encountered the most fiscal turbulence in Russia over this period, said WoodMac, although it has been less disturbing than in the 1990s.
“The most significant change was the introduction of an export duty in 1999 and mineral extraction tax in 2002-and the increase in their rates nearly every year since,” the analysts said. “Since 2004, the sliding scale export duty rate linked to oil prices seems to have worked effectively.”
In Kazakhstan, tax changes in 2004-05 increased the expected government take from future licenses, whether JV or PSC. “This stalled licensing activity, despite the attractive prospectivity of many areas,” WoodMac said. Licensing in Azerbaijan also stalled, primarily because of costly disappointments of recent exploration efforts and despite a gradual improvement of PSC terms.
Middle East, Asia
“Iraq and Kuwait have yet to sign any exploration and production contracts with foreign investors (although some are imminent), while Saudi Arabia recently opened for some gas exploration,” WoodMac reported. Syria made some concessions to new investors, but its government take remains high.
Meanwhile, the most investor-unfriendly fiscal changes in the Indian subcontinent have been regular increases in the royalty rates payable in India. “However, this affects production by the state operators only, as the rates are fixed in the marginal field JVs and PSCs with foreign investment.”
To stimulate development of marginal fields, the company said, Indonesia last year announced a plan whereby existing PSC contractors might regain in reimbursement more than they actually pay in operating costs. Investors throughout Australasia benefited from a general reduction in government take from new licenses. Australian investors saw gradual reduction in the corporate income tax rate and new incentives for drilling in frontier areas. New Zealand further reduced royalty for new gas developments. In 2003, the Papua New Guinean government reduced the income tax rate to 30% from 50%.
Africa
Terms remained stable for existing production in Africa, although agreements linking government take to project profitability (notably the deepwater Angolan PSCs) automatically reduce investors’ share of profit oil as prices increase.
WoodMac reported a flurry of licensing activity under relatively attractive terms in frontier areas in northwest and southeast Africa where there has been little activity in the past.
Nigeria’s radical reform of its natural gas fiscal regime, announced in 2004, still hasn’t been implemented. Still, WoodMac said, “As other countries look to commercialization of gas discovered under oil-based PSCs (e.g., Angola, Equatorial Guinea, Mauritania), we expect extensive debate over the terms and some innovative solutions.”
The company reported some reductions in the contractor take for new acreage, notably in deepwater Nigeria (higher royalty, lower cost recovery ceilings), Sudan (lower profit share), and Egypt (excess cost oil reverting to Egyptian General Petroleum Co., lower profit share). Most of the deterioration in the contractor’s take, however, is the result of either negotiation or a licensing auction, with the net increase in government take largely self-inflicted by an industry hungry for new acreage.
In Angola, companies continue to offer high signature bonuses, and companies last year offered very aggressive terms to secure prime blocks in Algeria’s sixth licensing round and under Libya’s fourth-generation exploration and production-sharing agreement (EPSA IV).
Watching Libya
EPSA IV, the first tender of Libyan exploration areas in more than 2 decades in which US and UK companies were permitted by their governments to participate, provides insight into modern contract terms and bidder competition in a major auction of excellent prospects during a period of high price expectations.
“All government folks are watching very closely things like the Libyan license rounds,” Johnston said. “It was one of the first really significant offerings in this new oil price era,” he reported. “The universe of fiscal terms that exists today for the most part was forged in an era of much lower oil prices.”
The first Libyan exploration license round, in January 2005, established “a new historical landmark,” Johnston said (OGJ, Apr. 18, 2005, p. 29). The terms carved out by industry were tough and relatively unforgiving, he added. Companies bid an “M factor”-a share of gross production for Libya’s National Oil Corp. (NOC)-and a “B factor” (signature bonus). License awards would go to companies bidding the highest M factor, with the signature bonus to be the deciding factor in the event of a tie between bidders.
Signature bonus bids that accompanied the M factor bids averaged $8.8 million/block, or $4/acre. The signature bonus is “most painful” to the contractor, Johnston said, “because it is paid regardless of whether or not a discovery is made, and bonuses are not cost recoverable.” The other bonuses are all contingent upon making a discovery that gets developed and produces hydrocarbons, Johnston said.
In older Libyan contracts, the M factor was set at 65%; NOC would take 65% of gross production and pay 50% of capital costs and 65% of operating costs. By contrast, the high bid for one of the 15 blocks offered in January set production shares of 87.6% for NOC and 12.4% for the contractor.
Winning bids in the second Libyan EPSA IV round in October 2005 offered even higher government-take bids than the first round (OGJ, Oct. 24, 2005, p. 39).
EPSA IV posed a significant risk of overbidding. When companies overbid, threshold field size for development can become very large, said Johnston. It may cause problems for both the host government and participating companies by marginalizing fields that otherwise would be economically feasible.
“Overbidding with signature bonus bidding on the other hand does not have the same effect on field size thresholds,” Johnston said. “Overbidding with production or revenue-based taxes or the equivalent means that there will likely be numerous delays followed by renegotiations for the relatively smaller discoveries in the wake of the EPSA IV round.
“There are going to be some fairly large discoveries that will not be large enough to develop economically with these terms. Yet, if oil prices remain much above $35/bbl,” Johnston said at the time, “some of the winning bidders are going to look like geniuses.”
Licenses awarded in the first EPSA IV round averaged just over 2 million acres each-“slightly larger than average for nonfrontier acreage these days, but it is not terribly unusual,” said Johnston. “The larger the block, the greater the risk a company will accumulate an inordinately large sunk cost position prior to discovery. When governments want to limit their exposure to exploration risk, choice of block size is an important consideration.”
Although the sealed bid auction is common in the industry and works well with highly prospective acreage, “much of the world’s acreage is not as exciting as Libyan acreage,” Johnston said. “Most governments, therefore, are not in a position to simply tender their acreage through a sealed-bid round like EPSA IV and expect an adequate response. With less exciting acreage, governments must be more creative.”
