The Resurgence of Iran Upstream: Will Rewards Outweigh Risks?

By Syd Nejad 18 Dec 2015

When the world powers signed the Joint Comprehensive Plan of Action with Iran on its nuclear ambitions, the news was received negatively as the market was in an over-supply condition. But Iran’s ambition to attract USD 180 billion to its upstream oil and gas industry and boost crude production to 5.7 million B/D by 2020 has led the country to alter its previous buy-backs to resemble production sharing contracts (PSCs) in the upcoming 2016 licensing round. The first Iran Petroleum Contract (IPC) licensing round is expected to start in the second quarter of 2016 and the final list of the projects is expected to be announced in a summit in London in February. Development of competitive drainage fields and improved oil recovery (IOR) projects of major fields are expected to show up in the first round, and most of the exploration blocks expected to be pushed to the second and third rounds. 

Iran’s National Iranian Oil Company (NIOC) is aiming for a 1 million B/D production boost through the licensing round, of which 150,000 B/D is expected to come from competitive drainage fields, approximately 300,000 from IOR projects, and approximately 550,000 B/D from major fields discovered over the past two decades. 

More than 70% of Iran’s crude production comes from fields with 50 years of life or more. Major investment is needed to offset the 8% to 10% decline in Iran’s 3.2 million B/D crude production and turn the curve upward. At the field level, NIOC’s priorities are competitive drainage fields (23 fields including South Pars and its oil-layer), high-impact fields (Azadegan, Yadavaran, Yaran, Darquain), and major enhanced oil recovery (EOR) and IOR fields (such as Ahwaz, Marun, Gachsaran, Bibi Hakimeh and Aghajari). NIOC’s estimation of the cost of Iran’s barrels is approximately USD 8-10/bbl. Our analysis suggests that finding and development (F&D) costs plus operational expenditure (Opex) of Iranian fields can have a range of USD 8-16/bbl of reserve. 

The country’s production comes from more than 2,200 producing wells in more than 100 oil fields of which about half are underinvested and/or shut in. 80% of the reserves are in carbonates and the remainder in clastics, and the crude oil density ranges from 20 °API  to 41 °API gravity with medium sulfur content.

NIOC’s foreign investment is limited to Rhum field in the UK North Sea with 50% working interest, which has been shut in since 2010 due to the sanctions, and Shah Deniz in Azerbaijan, with 10% working interest. Both fields are operated by BP. 

Technology transfer and building local capacities are among the strategic objectives of the IPC. To serve this purpose, IPC has a tiered base remuneration system that allows increase of the fees to companies on each produced barrel if the target is overachieved. The model is designed to encourage international oil companies (IOCs) to deploy the latest technological advancement in reservoir management, optimization, and production.

A quick review of the Iranian projects developed between 1995 and 2005 indicates that the capital-intensity of greenfield onshore projects in Iran could be around USD 10,000-15,000 per flowing barrel. Accounting for 3% annual inflation between 2000 and 2015, this is approximately a third of the same for unconventional fields in North America.

Iran is also ambitious in developing its gas production and export capacity. Iran needs 3%-4% annual growth in gas production to meet its 35 Bcf/D production growth target by 2018. Our analysis indicates that the target would likely be met in 2020. Currently, the country produces about 25 Bcf/D of gas, of which 20.7 Bcf/D is marketed; 2.7 Bcf/D is reinjected for reservoir pressure maintenance and improved oil recovery; and about 1.6 Bcf/D is vented and flared. 

The country has potential to export 3–5 Bcf/D to its neighboring countries. Pipeline expansion projects to Oman, Turkey, Pakistan, and Iraq have been launched and are in different stages of completion. Development of Iranian gas fields seems equally attractive given the growing domestic and regional demand.

Iran Petroleum Contract Vs. Buy-Backs

At the 2016 IPC licensing round, companies will bid coefficients for different aspects of the development plan, including but not limited to minimum contractual work commitment, production plateau, unit Opex, fee per barrel, and the speed of cost recovery. A matrix will calculate each bidder’s score. Other factors that come into the play are complexity factors such as development vs. and geological possibility of success in case of exploration blocks. 

Generation three technical contracts famous in Iran as buy-back contracts attracted approximately USD 50 billion between 1995 and 2005. Nearly all investors departed when the sanction pressures increased between 2010 and 2014.

Iran’s first oil started in 1901 under a concession, which then turned into a PSC in 1951. It went through revisions until the Iranian revolution in 1978 from when the right of producing and owning natural resources, including oil and gas, was only given to Iranian government on behalf of Iranians. Booking reserves is still one of the red-lines set by the Iranian constitution.

Although NIOC’s buy-back format was not the best of technical-service contracts, the 15% to 18% rate of return on investment was attractive enough to engage several IOCs in the 1990s and the first few years of the new century. Under the buy-backs a joint master development plan was prepared, parties agreed on a ceiling of capital expenditure (Capex) investment, a cost-recovery period was negotiated, and a fixed rate of return was agreed upon. IOCs provided the Capex and developed the field. The spent Capex was treated as a loan to the state which then produced annuity payments from the onset of production or the achievement of the production target until the end of the contract term. Through payments, IOC recovered Capex, Opex, and bank charges accrued during the development phase. The IOCs could also be paid in kind. The development phase usually was 2–4 years and the production phase was approximately 5-10 years.

The current offering, IPC, is a service contract but tries to borrow some of PSC’s advantages. Booking of reserves is a possibility now (for competitive drainage and high-risk fields), while several shortfalls of the buy-backs seem to have been addressed (see Table 1).

Technology goals that NIOC pursues with the IPC licensing round can be summarized as follows:

•    IOR/EOR related technology. High-tech basin and reservoir modeling, hi-resolution seismic interpretation, reservoir characterization, waterflood schemes, gas injection, hydraulic-fracturing, reservoir management, and optimization.
•    Sour gas handling know-how and hardware, in particular, for the South Pars field.
•    Small-scale liquefied-natural-gas and gas-to-liquid technologies. 
•    Exploration for gas and gas monetization onshore to support growing domestic demand and serve/expand regional export contracts. 
•    Exploration in the Caspian Sea and Persian Gulf; a low priority, but a need as NIOC lacks extensive exploration expertise, especially in the offshore. 

In this round, majors and super-majors can offer a package deal. They bring in the technology, financial strength, political stability, and organizational capacities. Majors also have bigger tolerance and more experience with the risk profile. Mid-cap exploration and production companies engaged at the time of buy-backs are expected to show up again. They may not bring a heavy-weight political tie with their respective government but if they demonstrate their competitive advantage and target a niche, they would have a good chance in securing below-50,000 B/D assets (which there are many in the IPC project list). Oilfield service companies would have a good chance in the upcoming IPC round as technical-service contracts fit them the best. 

Iran’s Risk Profile

Ongoing conflicts with Saudi Arabia and Israel and anti-West political views of the leadership drags Iran’s investment score down. Business Monitor International Research awarded a score of 28.1 out of 100 to Iran’s trade and investment risk. This places it in the fourth highest risk position regionally out of 18 countries.

Higher country risk translates into higher insurance rate and higher cost of capital. This is while the country still carries a dual-exchange rate system, and has double-digit inflation rate. Legislation and jurisdiction system are well-defined and documented but at the time of execution one notices how interpretive they can be (Fig. 1).

Fig. 1— An analysis of Iran’s strengths, weakness, opportunities, and threats (SWOT).

The business community and private sector in Iran has a long history of trade with international companies but mostly in the agency and dealership format. However, long lasting win-win business relationships through JVs and partnerships is not well experienced.

Our analysis rates Iran’s above-ground risk at 5.7, with politics contributing 20%, operational environment 20%, regulatory framework 25%, business climate 20%, and economics 15%. This is on a 0–10 scale where higher score means higher risk. We estimate the country’s below-ground rewards at 8.2, and the higher number means higher reward. This score assumes resource base to contribute 45%, availability 20%, marketing 20%, and valuation 15%.

Participation in 2016 IPC licensing round should not be treated similar to bidding for a license in Norwegian Continental Shelf or Gulf of Mexico. One cannot afford to show up right at the opening, purchase the bid packages, bid, and hope for the best. Understanding the business culture along with learning and appreciating local values could be a good starting point. Companies need to know NIOC and learn their concerns, objectives, and goals. Planning and developing an engagement strategy is vital. 

Iran’s petroleum minister repeatedly has emphasized that Iran will boost production despite the low-price environment. Some market analysts believe that the current low-price environment already takes into account the negative psychology of Iranian crude hitting the market in Q1 of 2016; however, it is hard to estimate the extent of the impact. 

Historically, OPEC has internally absorbed the production boost of its members and has committed to its overall budget. However, the cartel’s recent strategy to secure its market share may suggest that Iran’s production boost would not be absorbed by its members, but used as a stronger push against further development of unconventional resources.

In a low-cost environment, to satisfy the shareholders and keep reserves life index high, IOCs and independents may have to diversify their portfolio. Iran’s low-cost barrels may offer relief to the current low-price environment for those who dare the above-surface risks of the country.

Syd Nejad, SPE, is the CEO and managing partner of NAFT Energy. He leads the company’s investment and engagement in oil and gas projects in emerging markets. Nejad has several years of experience in upstream oil and gas, including strategy and corporate planning, acquisition and divestiture, portfolio optimization, asset management, production and field development, and reserves and reservoir exploitation and engineering. His previous positions include development and planning leader for oil sands at Statoil, asset manager for heavy oil and gas at Husky Energy, Persian Gulf and Iran area manager at Weatherford, and Pakistan country manager at Baker Hughes Inteq. Nejad has a bachelor’s degree in electrical engineering from Shiraz University and an MBA from the University of Wales. He can be reached at syd@NAFT.ca.