Long-pending and extensive amendments to Algeria’s 2005 Hydrocarbons Law cleared parliament in January 2013 and were passed into law shortly after. The changes were made in part to attract investment into unconventional resources and stoke interest in new bidding offers, following three rounds in recent years that produced disappointing results.
HISTORY: The 2005 law was itself a sizeable change to the 1986 regulatory code. Hitherto restricted in exploration and production (E&P) contracts, in which state-owned Sonatrach had a 51% share, foreign firms had that limitation reduced in the 2005 reforms. For future contracts, the production-sharing arrangement was replaced by a more modern system of royalties and taxes. These included a surface tax and a petroleum revenue tax, as well as taxes relating to water use and flaring. Foreigners were allowed to build their own pipelines – previously a Sonatrach monopoly – and invest in downstream activities such as refining, liquefaction, storage and distribution.
Sonatrach’s dual role as producer and regulator was scrapped. Two independent regulators were set up: the Hydrocarbons Regulatory Authority to supervise E&P activities and ALNAFT effectively to assign them – conducting bidding rounds for exploration perimeters, dealing with the resultant contracts and approving the development plans that eventually emerged from successful exploration efforts.
In 2006 more adjustments were made to the code. Sonatrach’s right to a 51% share in activities dealing with exploration, production, transport and refining of hydrocarbons was reinstated (reinforced by a general requirement for 51% Algerian stakes in most firms in a finance law in 2008). This was followed by the imposition of a windfall profits tax for new investors when the price rose above $30 per barrel.
BIDDING: Despite the various changes, or perhaps because of them, subsequent bidding rounds did not meet expected results. In 2008, 70 companies pre-qualified for a round offering 15 permits, but there were just nine bids for four of them. In 2009, on the basis of six bids, three permits were assigned, and in 2011 it was just two. The factors behind this are multiple, including the fall in capital expenditure by oil firms following the global slowdown as well as plateauing international demand, alongside an element of uncertainty over the domestic regulations.
Still, those investors that did participate had some luck. Russia’s Gazprom discovered gas at El Assel, the consortium of Thailand’s PTTEP and China National Offshore Oil Corporation looks set to start production at Hassi Bir Rekaiz in 2014, while Total and its partner Partex have similar expectations at Ahnet. Yet in a bid to accelerate exploration and identify new reserves – including unconventional sources – Algeria is looking to reinvigorate bidding rounds, prompting some of the changes to the regulatory code.
KEY REFORMS: The new code helps clarify areas that were uncertain in light of the 2005 and 2006 reforms. One amendment specifies that oil and gas pipeline transport activity should be exclusively performed by Sonatrach, and that the purchase of land involved in such activity should also be the exclusive preserve of the parastatal or its subsidiaries. The 51% rule is also maintained for E&P, though Sonatrach is now obliged to make clear in advance what share it proposes and what amount of investment it is prepared to make on the basis of that share.
Other areas of the code are being relaxed. A prospecting authorisation can now be renewed for a maximum of two years, over and above the previous term of two years. Firms that have performed prospecting activities will be in a preferential position when an E&P tender occurs: provided those prospecting activities conform to what is laid out in the E&P tender, they will have the right to match the best offer. If they do not do that, they are entitled to have their prospecting expenditures recognised by ALNAFT as exploration costs, and have them reimbursed by the company that does get the contract.
There is also a concession for any company that embarks on exploration and makes a discovery before the standard seven-year exploration period is up. It can then be allowed an extra two years by ALNAFT for “delineation” of that discovery.
Gas producers also benefit from an extension: a supplementary period of five years is now allowed on top of the standard 25-year exploitation period for gas fields. Any part of the standard seven-year exploration period that they did not use for exploration can also be tacked on.
There is special treatment for “unconventional oil and gas”, which gets a detailed definition for the first time in these amendments. Various possible criteria of the sorts of geological formation where oil and gas must be located to qualify as unconventional are laid down. Definitions are in terms of permeability (or lack thereof), high viscosity, high pressure or high temperature of reservoir bottoms.
While some numerical definition is given for permeability, an alternative definition – and the only definition in the case of clay or shale formations – is that the formations in question can only be dealt with by horizontal wells and tiered fracking.
Those dealing with hydrocarbons “primarily characterised” by one of the criteria of unconventionality benefit from longer E&P periods than operators dealing with more standard circumstances. Starting from the day the agreement enters into force, the “unconventionals” have a pilot period of four years on top of the normal seven years allowed for exploration – effectively 11 years to take account of the difficulties involved in shale. The production period is then 30 years for unconventional oil and 40 for unconventional gas – compared to just 25 years for conventional resources of both varieties. An additional five years of production can be had on request – and five years on top of that, should ALNAFT agree, implying a potential 61 years from start to finish.
TAX: The amendments also envisage kinder tax treatment for all and special breaks for those in certain categories. Petroleum income tax now varies between 20% and 70%, rather than the previous 30-70%. The rate payable is calculated not, as hitherto, on turnover – the cumulative value of output since the contract’s entry into force – but on annually updated profitability. Unconventional oil and gas receive particularly favourable tax treatment.
Those exploring for or producing from unconventional deposits pay half or less of the surface-area taxes paid by other producers, and pay petroleum income tax in the range of 10-40%, depending on profitability. They also enjoy various types of deductibility – for instance with regard to the cost of buying gas for recycling, or of training Algerian staff.
Other benefits apply not just in the case of unconventional oil and gas, but also those sites which are in “underexplored areas”, characterised by complex geology or lacking in infrastructure. All such schemes enjoy a reduced royalty rate. Along with the category of “small deposits”, these classes qualify companies for a lower rate of 19% (rather than the normal 30%) of the Additional Tax on Income, except in the case of extraordinarily high profitability.
TIME WILL TELL: The impact that these regulatory changes will have on bidder interest is hard to predict, given the tighter global market resulting from US shale production and continuing low levels of demand in Europe, Algeria’s primary gas market. The need to increase production, coupled with Algeria’s own export targets, could heighten investor interest, provided that further efforts to improve the country’s business climate are put in place. Indeed, there is potential interest already. By June 2013 consultations had been held with 80 companies, with 70 of these firms pre-qualifying for the 2008 bidding round, but only nine made valid bids. The outcome of the next round will serve as a provisional verdict on the effectiveness of the Hydrocarbons Law amendments.
Read More from OBG
