Following over a decade’s debate on 17 drafts of the long-awaited Petroleum Industry Bill (PIB), authorities hope to enact the reform by year-end 2013. With debate shifting from the federal executive branch to parliament, and the 2015 elections fast approaching, time is of the essence. Despite opposition from international oil companies (IOCs) due to financial concerns and the role of the Federal Ministry of Petroleum Resources (FMPR), certainty on future fiscal terms is crucial to fostering the investment in exploration and production (E&P) needed to boost production to 4m barrels per day (bpd) in line with the government’s goals and replenish proven reserves already in decline.
INSTITUTIONS: Efforts to reform the sector and harmonise the existing 16 pieces of legislation started in 2000. While a first piece of legislation was presented to the National Assembly in December 2008, the Federal Executive Council issued the latest 223-page draft in July 2012, meant to be the final draft with only amendments allowed. The key aims of the draft are to boost production to 4m bpd by 2020 by restructuring the Nigerian National Petroleum Corporation (NNPC), delineating regulatory functions from operatorship, and revising fiscal terms for both onshore joint ventures (JVs) and offshore production-sharing contracts (PSCs) to optimise the government’s take.
The draft envisions the creation of six new institutions and unbundling NNPC, separating regulatory from commercial functions, as central to the reform process. A Petroleum Technical Bureau (PTB) within the FMPR will provide technical and policy formulation support, replacing NNPC’s Frontier Exploration Services Division. According to the draft legislation, the existing upstream regulatory functions of the Department of Petroleum Resources (DPR) and NNPC will be restructured into the Upstream Petroleum Inspectorate (UPI), covering both technical and commercial aspects, setting and monitoring standards, issuing permits and conducting licensing rounds. The Petroleum Equalisation Fund (PEF), in charge of subsidy payments, will be kept in place until the downstream sector is deregulated on the ministry’s decision. The Petroleum Technology Development Fund (PTDF) will also continue to support the development of new technologies, research and training. The downstream functions of the DPR and the Petroleum Products Pricing Regulatory Agency (PPPRA) will be integrated into a Downstream Petroleum Regulation Agency (DPRA), in charge of licensing, technical regulation, and oil transport infrastructure, environmental standards and domestic gas supply.
NEW ROLES: Furthermore, NNPC will lose its regulatory functions under the new legislation if passed as it stands, and its commercial functions will be unbundled into three successors: the National Oil Company (NOC), the National Gas Company (NGC) and a new National Petroleum Assets Management Corporation (NPAMC). The latter will replace NNPC’s existing subsidiary, National Petroleum Investment Management Services (NAPIMS), initially holding NNPC’s stake in six unincorporated JVs before further expanding its asset base.
The NOC, most likely a successor to NNPC’s current operator subsidiary, the Nigerian Petroleum Development Company (NPDC), is expected to list 30% of its shares on the domestic stock exchange within six years of the law’s enactment. The NGC, the successor of the current NGC, will manage NNPC’s gas interests and is expected to float a 49% stake.
UNCERTAINTY: While private oil operators welcome the unbundling of NNPC into commercially viable units, uncertainty remains over the extent of the FMPR’s influence in establishing the new companies’ articles of association. Similarly, under the current PIB draft, the minister of petroleum resources has the right to revoke any licence without reason and the right to award blocks on a discretionary basis. The minister also has the power to set royalties, fees and rentals on a sliding scale and grant gas-flaring permits.
Observers like the EU have called for such regulatory powers to be devolved to the new independent regulatory institutions. “The powers of intervention that have been a feature of the [minister’s position] ever since [it was created] will be preserved and even strengthened,” the EU noted in a multi-stakeholder analysis of the PIB published in March 2013. “This would give the office holder an unprecedented plenitude of discretionary power, lowering checks and balances, and curbing transparency in the sector.”
FISCAL TERMS: Under the current Petroleum Profits Tax Act (PPTA), Nigeria maintains parallel systems for onshore and shallow-water production in JV schemes with NNPC and under PSCs for deepwater offshore ventures. Production after costs on JVs is taxed at 85%, with a concessional 65.75% rate during the start-up phase, while investors are granted a capital allowance and investment tax credit of 20% for the first four years, 19% in the fifth and 1% retained on the company’s books. An additional 2% is levied as an education tax and 3% paid to the Niger Delta Development Commission (NDDC) for development projects.
JV gas projects are taxed at 30% with a 7% royalty on gas sales. Energy consultancy Wood Mackenzie estimates the effective government take on JVs ranges from 83% to 90% of pre-take revenue excluding NNPC equity (usually of 60%, but of 55% on SPDC blocks), and in the 92-97% range including NNPC equity. Under the system of PSCs for deepwater offshore blocks, investors pay a royalty rate of 0-8%, 50% tax rate under PPTA and receive a 50% investment tax credit. The agreements also allow for full foreign cost deductibility. Wood Mackenzie estimates the effective government take on PSCs averages 66%, in line with the world average of 64-70%. While this is higher than similar low-risk regions like the Gulf of Mexico (which averages 41%) and offshore Brazil (60-65%), the 0-8% sliding scale of royalty rates based on water depths and the absence of cost recovery limits allows Nigeria to remain competitive.
NEW STIPULATIONS: Under the proposed new fiscal regime of the PIB, the effective government take will increase on the back of new and higher taxes from 86% to 91% for JVs, 0% to 60% for JV gas and 30% to 77% for PSCs, according to figures quoted by the EU in March 2013. However, the FMPR has argued that the government take on PSCs would be only 73%.
Industry association Oil Producers Trade Section (OPTS) of the Lagos Chamber of Commerce & Industry argued that raising the PSC tax rate to 55% would hurt investment. The PIB plans to switch from the PPTA, only applied to oil, to the Nigerian Hydrocarbons Tax (NHT), managed by the Federal Inland Revenue Services (FIRS) and levied on both oil and gas. The NHT would be levied at 50% of pre-tax profits for all onshore and shallow-water operations, and 25% for offshore PSCs (to be allocated to coastal communities). While there may be exemptions, it remains unclear whether the five-year PPTA concessions will be carried forward.
Firms will also pay 30% corporate income tax on top of the NHT, as well as a new 10%-of-profits tax to the Petroleum Host Community Fund (PHCF). While it remained unclear in mid-2013 how the fund would operate, it could push combined tax rates on JVs to over 90% if it is not tax deductible, according to brokerage firm CSL Stockbrokers.
CRITICISM: The OPTS, representing the views of IOCs, argues that the new rates would cause a 100% drop in new deepwater projects, 87% reduction in gas JVs and 23% for oil JVs, throwing into question some $109bn in IOC investments over the medium term. Drawing on Wood Mackenzie data, the OPTS argued that the 18-26% royalties, 55% tax, 20-60% government share of profit oil and incentives of only $0.34 per barrel of oil equivalent from PSCs would prove globally uncompetitive. “In its current format the PIB is adding further pressure to margins, which are already far lower in Nigeria than in other markets. IOCs will not pull out, but investment is definitely on the back foot,” Leslie Oghomienor, managing director of Russelsmith Group, told OBG.
Crucially, the new PSC terms cap foreign cost deductibility at 80%. OPTS points to Angolan terms of 0% royalty, 50% tax, 25-80% government share of profit oil and $1.84 per barrel incentives, as well as Equatorial Guinea’s 12-16% royalty, 35% tax, 10-60% share of profit oil and lack of incentives, as evidence of markets to which investment would gravitate if Nigeria carries out the above reforms. Effective government take of JVs post-PIB, at 91%, are higher than equivalent onshore and shallow-water terms in Angola (83%), Venezuela (82%), Oman (85%) and Norway (80%).
Indigenous oil firms have for their part criticised the lack of clear incentives and support for Nigerian producers in the bill. Despite this, several international observers have called for the proposed fiscal terms to be passed. The IMF called for swift enactment in its May 2013 public information note in order to create the necessary certainty to attract investments, saying “it would boost investment, government revenue and fiscal transparency”, while others consider the revised terms to be broadly in line with global standards. “We see the revised fiscal terms proposed under the PIB as internationally competitive even though oil producers’ margins will be reduced,” Niyi Yusuf, country managing director of global consultancy Accenture, told OBG.
STATE OF PLAY: The current bill presented to the National Assembly in July 2012 underwent two readings by early 2013. It must undergo public hearings of at least three months by both the House of Representatives and the Senate before its third reading, reconciliation of House and Senate amendments, approval by the minister of petroleum resources, and presidential signing. The House of Representatives started public hearings in Lagos, Port Harcourt, Abuja and Kaduna in May 2013, while the Senate had yet to set a date at the time of writing. As the debate shifted beyond parliament, political considerations between northern and southern states came to the fore, with public-hearing comments focusing on the PHCF, in addition to the 3% NDDC levy and the oil derivation of 13% of federal allocation accounts to the 10 oil-producing states.
“Negotiations on the PIB are hostage to a proxy war for the presidency between the north and the south,” Bismarck Rewane, CEO of Financial Derivatives, told OBG. “Yet given the natural rate of attrition of wells, Nigeria’s oil production could drop to below 1.5m bpd, which would cause severe fiscal strains.” Indeed, pressure to increase investment in E&P in inland areas like the north-eastern Lake Chad basin has mounted.
The House of Representatives had already amended the draft bill to establish a National New Frontier Exploration Agency prior to its public hearings. The New Nigeria Development Corporation, owned by 19 northern state governments, holds exploration rights to two blocks but has yet to start exploration. The FMPR announced in 2011 its goal of investing $1bn in oil exploration in the five inland basins of Chad, Anambra, Sokoto, Gongola-Yola and the Benue Trough by 2016.
Striking a balance between competing political and business interests from north and south, and between private oil firms and the government is especially pressing, given falling reserve replacement ratios. While the latest draft continues to suffer from a marked lack of clarity, passing this bill may be better than nothing at all for both the government and oil companies.