The Outlook for Natural Gas, Electricity, and Renewable Energy in Iran

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This report presents our analysis of supply and demand for natural gas and electricity in Iran and forecasts their future trends through 2040. We first discuss the outlook for Iran’s natural gas production and market demand and then quantify economic opportunity losses caused by suboptimal allocation of natural gas to various end uses. Subsequently, based on the projections made for individual consuming sectors, we forecast Iran’s future demand for electricity. Finally, we put the potential of renewable energy in Iran into context by comparing its future viability against other power capacity expansion scenarios, i.e. upgrading the existing gas-fired power plants and the addition of new units. 

Stemming from the development of supergiant South Pars gas field, Iran’s natural gas industry has shifted to a new paradigm: since 2000, production has increased from 230 to 750 mcm/d and is likely to rise to 920 and 1150 mcm/d by 2020 and 2040, respectively. The envisioned drastic drop in the production growth beyond 2021 is attributed to the smaller capacity of future greenfield projects, and the expected decline in production of the existing fields — particularly the South Pars field itself. Besides demographic drivers, the displacement of liquid fuels by natural gas for space heating, electricity generation, and the development of petrochemical plants and energy-intensive industries has given rise to such a soaring domestic demand that the amount of gas left for reinjection into mature oil fields has remained flat and the net trade of gas has been zero or negative. Although Iran’s total gas export (to Turkey, Iraq, Oman, and Armenia) may reach 100 mcm/d levels within the next five years, further expansion of the export capacity seems infeasible. Within the domestic market, the largest growth in natural gas demand will come from petrochemical and other industries, and the power sector. 

Figure ES-1. Historical data and projected natural gas supply and demand in Iran (1990–2040).

The Iranian government manages the demand for natural gas by setting sector-specific prices and quotas, the former of which is decided annually while the latter is adjusted dynamically. The mismatch between the selling price and allocation priority suggests that the demand structure (hence the total revenue) could have been vastly different had the price elasticities of different uses been factored in the pricing models. This discrepancy highlights the urgency for the country to accelerate energy price reforms and develop a competitive market for supplying natural gas to large buyers (e.g. petrochemical plants).

Figure ES-2. Allocation priority (horizontal axis), revenue (vertical axis), and consumption (circle size) of natural gas for different end uses in Iran.

Since 1990, Iran’s power generation capacity has expanded at an average rate of 2.4 GW/y to meet the average gross demand growth of 9.1 TWh/y. With a share of 85%, the sector heavily relies on natural gas as the primary source of energy, while shares of liquid fuels and hydro in 2016 were 9% and 5%, respectively. Our analysis shows that Iran’s electricity demand growth will likely decline from 6.8 to 3.8 TWh/y by 2040, reducing the need for annual capacity addition from 3.0 to 1.3 GW. Upgrading the existing power plants will add 10 GW capacity at a levelized cost of less than 1 ¢/kWh, while the levelized cost of marginal electricity generation by combined cycle plants ranges from 1.5 to 6.3 ¢/kWh depending on the opportunity cost of natural gas. We also show that, with a future levelized cost of ~ 4 ¢/kWh, publicly-funded utility-scale renewable energy (solar and wind) will become economically viable only if the selling price of displaced gas exceeds $150,000/mcm. Currently, the only uses of natural gas that satisfy this threshold requirement are transport (CNG), gas export, and reinjection into oil fields. While gas export and reinjection have some growth potentials, the market for CNG vehicles seems to have become saturated and hence any further expansion would require a market stimulus such as an increase in the domestic price of gasoline. At the current selling price for natural gas, investments in renewable energy with the objective of making more gas available to boost the production from the petrochemical industry is not economically viable.

Figure ES-3. Historical data and projected electricity consumption (1990–2040).

The Outlook for Natural Gas, Electricity, and Renewable Energy in Iran

Introduction

With 34 trillion cubic meters (tcm) of proven reserves, Iran possesses the largest recoverable natural gas resources in the world [1]. As over 80% of the country’s gas reserves is attributable to non-associated fields [2, 3] (deposits not associated with significant quantities of crude oil), development of natural gas and oil sectors in Iran, to a large extent, has been carried out independently. Between 1990 and 2013, production of natural gas in Iran ramped up from 110 to 500 mcm/d—implying an average annual growth rate of 17 mcm/d. Since 2013—in spite of limitations caused by international sanctions and a contraction of the domestic economy—Iran has managed to further increase its marketed gas to 750 mcm/d through completion of several new phases of the South Pars development project. As a result of such unprecedented growth, approximately 25% of Iran's total cumulative natural gas production has occurred within the past five years. Given the sheer influx of new gas from the South Pars field, the share of natural gas in the primary energy supply has surpassed that of crude oil since 2014 (Figure 1). On the domestic demand side, the annual growth in natural gas consumption, by large margins, has exceeded growth in liquid hydrocarbon consumption (Figure 1) to the extent that, except for transportation, natural gas has become the de facto source of energy for all sectors of the economy.

Figure1. Hydrocarbon production (left figure) and real GDP and hydrocarbon consumption growth rates relative to 1990 (right figure) in Iran.

Iran is the third largest producer of natural gas in the world, but an overwhelming majority of its supply thus far has been absorbed by domestic demand. Space heating (29%), power generation (24%), non-petrochemical industries (15%), petrochemical industry (13%), reinjection (9%), and transportation (3%) constitute the largest consumers of natural gas in Iran. With the expansion of the distribution grid to cover over 90% of households, natural gas has gradually replaced liquid hydrocarbons for space and water heating, resulting in an increase in gas consumption over the past twenty-five years of 180 mcm/d. Meanwhile, the amount of natural gas consumed for power generation increased by 140 mcm/d while consumption by petrochemical and other industries increased by 170 mcm/d. As a consequence of such rapid expansions on the demand side, the volume of gas available for reinjection into mature oil fields has remained flat at about 80 mcm/d—despite the pressing needs indicated by Iran’s official targets [4] while the country’s net trade in natural gas has been zero or negative.

Iran’s annual gross electricity production was 55 TWh in 1990 and 282 TWh in 2015, implying an average growth rate of 9.1 TWh per year. In the same period, the nominal power generation capacity of Iran increased at an average rate of 2.4 GW per year. As one would expect, the power sector in Iran relies heavily on natural gas. In 2016, shares of natural gas, liquid fuels, and hydropower in Iran’s power generation mix were 85%, 9%, and 5%, respectively (Figure 2).

Between 1990 and 2015, the mean efficiency of thermal power plants in Iran improved from 30.9% to 37.7% [5, 6], implying an average energy efficiency gain of 0.27% per annum. For the sake of comparison, the average world efficiency of thermal power stations is approximately 36.5%, while those of OECD (Organization for Economic Cooperation and Development) members located in Asia and North America are above 40% [7]. Figure 2 shows the thermal efficiency distribution of Iran’s power plants in 2015 [6]. Given the sizeable share of low-efficiency plants (i.e., old and/or simple cycle power stations), Iran has a significant potential for capacity addition through upgrading and modernization of its existing power plants. Of particular importance is adding steam turbine generators to the existing large-scale simple cycle gas turbine plants and revamping (or dismantling) old steam and gas turbine plants. For example, some 9 mcm/d of natural gas will be saved by upgrading 7.5 GW of low-efficiency power plants (i.e., less than 30% efficiency) to modern simple cycle combustion turbine (SCCT) with 40% efficiency.

Figure 2. Gross power generation by source of energy (left) and efficiencies of thermal power plants in Iran (right).

Besides fossil energy resources, Iran has a significant potential for renewable power. We estimate that the solar irradiance received by 1.7 million hectares (1.1% of the total) of Iran’s lands exceeds 270 W/m2 and there exists another 28 million hectares (17.3% of the total) where solar irradiance ranges from 250 to 270 W/m2 (Figure 3). As for the potential of wind power, 1.3% of Iran’s lands (2.1 million hectares) has a mean annual wind speed of 8 m/s and higher, which renders them suitable for harnessing this source of energy. Iran plans to increase the shares of non-hydro renewables in its total power generation capacity to 5% (about 4 GW) by 2021 [8, 9]. This not only allows for redirecting the displaced gas (or liquid fuel) toward other uses where a higher economic return can be attained, but helps improve air quality in major cities. Currently, the Ministry of Energy (Vezarat-e-Niroo) offers a twenty-year guaranteed feed-in tariff (FIT) contract for renewable power at higher rates compared to the selling price of electricity to the end users; i.e. 12 ¢/kWh for wind and 18 ¢/kWh for solar for the first ten-year period, after which rates are reduced to 5 and 13 ¢/kWh, respectively, for the second ten-year period. During the past four years, domestic and foreign investors have installed roughly 350 MW of renewable energy in Iran through power purchase agreement (PPA) mechanism, while several other energy farms with a total capacity of approximately 700 MW are at various stages of development [10].

Figure 3. Maps of Iran’s annual average global horizontal irradiance (GHI) and wind speed [11, 12].

Herein, we present the outlook for natural gas, electricity, and renewable energy in Iran until 2040. Specifically, projections are made for i) supply of natural gas, ii) natural gas allocation/consumption by sector, iii) electricity demand by sector and iv) costs of different power expansion scenarios. These scenarios are: installation of new combined cycle power stations, addition of steam turbines to single cycle gas turbine plants, retrofit of old steam plants, and use of non-hydro renewable energy.

Results and Discussion

In this section, we present our analysis of the outlooks for natural gas and electricity in Iran and discuss their mutual implications. To this end, we start by forecasting production of natural gas in Iran based on projected outputs from both existing and undeveloped fields. Then, we discuss natural gas allocation policy in Iran and predict its future consumption for all major end uses.

We also quantify potential opportunity losses caused by suboptimal allocation of natural gas to different sectors. Finally, we make sector-specific projections for future trends in electricity demand and evaluate the economic viability of alternative power generation scenarios—including gas-fired power plants, solar photovoltaic (PV) cells, and wind turbines—by which Iran can meet its future electricity demand.

Natural Gas Supply and Demand

The historical data and our future projections for natural gas supply and demand in Iran are shown in Figure 4. Contrary to the oil sector—where production capacity has been fluctuating in a narrow range (i.e., 500 kilobarrels per day) for a long time—Iran’s gas sector has seen profound changes over the past three decades. Between 1990 and 2017, Iran’s supply of marketed natural gas (including the amounts used for reinjection) has increased from 110 to 750 mcm/d. Completion of the South Pars development project—which is likely to happen around 2021—is expected to boost Iran’s supply of marketed natural gas to 960 mcm/d. In addition to the uncompleted phases of the South Pars field, many undeveloped gas fields can be exploited in the future. However, despite the modest potential of these fields, we predict that the gas production growth rate in the post-South Pars development era will drastically decline.

• The unprecedented rate of new influx of natural gas between 2013 and the completion time for the development of the South Pars field (around 2021) is partly attributed to previous delays in the completion of the earlier phases that are now coming online along with the subsequent phases. A review of ongoing and future development plans for other gas fields reveals that a similar event is unlikely to occur in the foreseeable future.
• Similar to South Pars, most of the undeveloped gas fields of Iran—such as Kish, North Pars, Golshan, Ferdowsi, and Farzad A&B—are located offshore and are thus inherently expensive to develop. However, these fields by no means will benefit equally from the economy of scale and manufacturing-like development that helped to advance the South Pars project.
• Future production from undeveloped gas fields will be partly offset by the decline in the rate of production from the existing fields. These fields' total production will be upward of 1,000 mcm/d. Therefore even a slight annual decline of 1% would lead to a 10 mcm/d loss in production. Of particular importance is an expected pressure drop in the South Pars/North Dome field in the near future as evidenced by recent activities of Iran and Qatar to mitigate its adverse impact on future production.

A list of Iran’s major natural gas fields and refineries and more information about ongoing and future gas development projects are provided in Tables A1 & A2 in Appendix A, respectively.

Figure 4. Historical data and projected natural gas supply and demand in Iran (1990–2040).

On the domestic demand side, the rise in natural gas production coincided with an equally strong growth in domestic demand which was primarily led by the expansion of the power and natural gas distribution networks. We estimate that by 2040 the use of natural gas for space heating and power generation will reach 220 and 280 mcm/d, respectively. Moreover, the use of natural gas in petrochemical and other industries has expanded to a level such that their total intake (about 200 mcm/d) is now comparable to that of space heating. As a result of recent investments, Iran’s total annual petrochemical output is expected to reach 105 million tons by 2022 [13]. If the plan materializes as intended, Iran's total petrochemical production will increase by 80% compared with the 2015 baseline, raising natural gas consumption from 72 mcm/d to about 130 mcm/d.

Gas reinjection into mature oil fields represents another strategic use of natural gas in Iran. Immiscible injection of gas into fractured carbonate reservoirs, which constitute a large share of Iran’s oil reserves, has proven to be a relatively simple and yet effective method for mitigating production decline and enhancing the ultimate recovery from such resources. Our previous study showed that, on average, injection of 1 mcm of gas in such oil fields in Iran would boost oil recovery by approximately 4 kilobarrels (kbbl) [14]. This would mean that, at an oil price of $50/bbl, revenues of approximately $200,000 would be obtained for each million cubic meters of gas injected. Although a dozen mature oil fields in Iran use gas injection for improved recovery, the allocated amounts of natural gas for this purpose have consistently been far from ideal; namely, about 80 mcm/d while official plans were targeting 250–300 mcm/d levels. The provision of gas for injection into oil fields primarily relies on gathering and recompressing the associated gas produced in the oil fields of Khuzestan province and, to a lesser extent, on dry sour gas produced in South Pars phases 6, 7, and 8 that is sent to the Aghajari field during the off-peak seasons.

Besides greenfield projects, Iran has a sizeable potential for increasing its available gas for reinjection or other uses through gathering, recompressing, and treating the flared gas. Iran is consistently among the top four gas-flaring countries in the world, flaring about 33 mcm of associated gas per day (Figure 5) [15]—equivalent to 120% of the production capacity of a standard phase of the South Pars field. The flare intensity of Iran, defined as the ratio of flared gas to oil produced, is about 11.7 mcm/mmbbl. Although flaring does not impose a significant direct cost on Iran, the opportunity cost of flared gas for the country is very high. For example, based on recent clean development mechanism (CDM) projects, flare reduction costs have been estimated at between $60,000/mcm and $80,000/mcm [16], while reinjection of gas into declining oil fields, as outlined above, would yield an estimated revenue of $200,000. In addition, flare reduction results in major environmental benefits, both locally (air pollution reductions) and globally (greenhouse gas emission reductions). The latter has come to the forefront under the Paris Agreement on climate change, wherein Iran set relatively ambitious targets. Important steps, such as the AMAK project [17] (to be completed in 2017 at an estimated cost of $500 million), are meant to improve the utilization of associated gas in Iran.

Figure 5. Iran’s gas flaring volume and flare intensity (defined as the ratio of the flared gas and total crude oil recovered).

Figure 6, in the simplest form, summarizes the selling price, amount, and allocation priority of natural gas to the main consuming sectors in Iran. Natural gas allocation priorities have been inferred by analyzing energy policies and observing how the government manages natural gas shortages during the peak season. The allocation priorities outlined here are solely aimed at explaining how natural gas is currently distributed among different sectors, which can be different from the government’s intended plans for the future.

In rough terms, natural gas in Iran is uniformly priced at $34,000/mcm for residential, power, and industrial consumers (including petrochemical plant fuel) despite the profound differences in the price sensitivities of these consuming sectors. For the sake of comparison, the above price is almost 50% lower than the Henry Hub gas spot price ($71,000/mcm in 2016) and 90% lower than the average residential gas price in the United States ($355,000/mcm in 2016) [18].

Figure 6. Allocation priority (horizontal axis), revenue (vertical axis), and consumption (circle size) of natural gas for different end uses in Iran.

Having no immediate replacement, provision of natural gas for space heating has consistently been the government’s highest priority as evidenced by the redirection of more gas for this sector to satisfy the peak demand in winter. Similarly, the power sector constitutes another strategic and hence high-priority use of natural gas in Iran. However, in contrast with space heating for which natural gas has no immediate replacement, the power sector has been partially fueled by liquid hydrocarbons (diesel and fuel oil) to avoid gas shortages for residential and commercial buildings. Given high economic and environmental costs, we expect that Iran will terminate the use of liquid fuels for power generation in the near future.

Over the past fifteen years, with the primary objective of reducing national gasoline consumption, Iran has offered significant incentives to promote the use of CNG vehicles and has heavily invested in CNG refueling infrastructure and tank manufacturing. With over four million vehicles on the road, Iran currently has one of the largest CNG fleets in the world. However, the market growth for CNG-based vehicles has almost entirely diminished in recent years. This implies that further market growth will depend on more lucrative incentives (e.g., discount relative to liquid fuels) or improvement of vehicle performance (e.g., longer driving range and more power). The added value assigned to the use of natural gas for the CNG fleet ($450,000/mcm) in Figure 6 is calculated based on gasoline's price in the Persian Gulf (about 40 ¢/liter).

Iran’s gas exports to neighboring countries have so far been very limited due to strong growth in domestic demand, past political concerns, and lack of infrastructure. Iran now exports about 30 mcm/d of natural gas to Turkey at an average price of $250,000/mcm and sends 1 mcm/d natural gas to Armenia in exchange for electricity. Gas exports via pipeline are expected to reach Baghdad (about 25 mcm/d), Basra (about 20 mcm/d), Oman (28 mcm/d), and Armenia (increasing to 3 mcm/d) in the next five years. Appendix B provides a more detailed discussion on the prospect of Iranian gas exports outside its neighbors.

The price of natural gas fuel offered to industries, including public and private petrochemical plants, is equal to 27% of the average industrial price of natural gas in the United States ($124,000/mcm in 2016) [18]. As a result of such heavily discounted gas prices in Iran, large investments have been made in upstream petrochemical industries (see Appendix C), often without the full vertical integration that is a prerequisite for profitability if fuel and feedstock are priced competitively. Total natural gas consumption in petrochemical complexes increased by over 60 mcm/d in the past two decades. We estimate that, on average, the added value from consumption of 1 mcm of natural gas (or its equivalent) in Iran’s petrochemical industry is about $155,000.

Reinjection of natural gas into declining oil fields, despite its comparatively high economic return in the long run, has been given the lowest priority among the end uses of natural gas, as it is perceived as nonurgent or postponable. In addition to the value of recovered crude, a partial recovery of the injected gas after depletion of a reservoir’s oil reserve adds to the real benefits of this application, particularly if the injected gas is extracted from common fields between Iran and its neighboring countries, such as South Pars (Qatar), Farzad A&B (Saudi Arabia), Arash (Kuwait), and Hengam (Oman). However, the added value for gas injection in Figure 6 refers solely to the direct revenues associated with crude recovery, as other economic and strategic benefits of gas injection have not been considered.

Electricity Sector

Future Electricity Demand

In this section, we explore long-term demand for electricity in Iran. This forecast is based on projections made for each individual sub-sector, including residential, industrial, public, street lighting, and agricultural uses. As shown in Figure 7A&B, from 1990 until 2016 the total residential power demand has risen from 17 to 78 TWh while the consumption per subscriber has increased from 2,000 to 3,000 kWh. The significant rise in residential electricity consumption until recent years can be attributed to the expansion of the grid network to rural and more remote areas of the country as well as the growth in the population itself. However, we anticipate that growth in residential consumption will diminish by 2040 as the population is only expected to grow by another 10 million. That the grid penetration has almost reached its full potential is evidenced by the drop in ratio of population to the number of subscriptions from 6.8 in 1990 to 3.0 in 2015. This ratio—population size to number of subscribers—is comparable to the average size of a household in Iran, 3.3 persons, according to the 2016 census [19].

The gross domestic product (GDP) generated by industrial activities and the corresponding electricity demand from 1990 to 2015 are shown in Figure 7C&D. As can be seen in this figure, the increase in industrial electricity consumption has substantially surpassed the GDP growth: considering 1990 as the reference, the ratio of growth in industrial electricity demand to respective real GDP growth by the sector has been close to 2.8 on average. This higher-than-proportional rise in demand can be explained by the fact that a large portion of Iran’s industrial GDP is generated by the oil sector, for which the level of activity has roughly remained constant. Therefore, one can expect to see a closer correlation between the growth rates in the power demand and generated GDP of other (non-oil) sectors of the industry. In the absence of any market signals that would indicate a different trend, we assume future industrial electricity consumption will follow the previously observed trajectory. This would mean that Iran’s industrial electricity consumption will rise to 85, 110, and 135 TWh/y by 2020, 2030, and 2040, respectively.

Figure 7. Projection of sector-specific electricity demand in Iran based on historical data, future development plans, and other influential exogenous factors.

Figure 7E illustrates electricity consumption by the agricultural sector, which is primarily used for operating water wells and irrigation pumps. Iran is estimated to have 500,000 water wells, of which about 50% have already switched from diesel to electric operation as the government intends to monitor and control volume of water extracted per well while reducing farmers’ costs. This transition also benefits the government by reducing the cost premium paid for liquid fuels (diesel and fuel oil). In order to forecast future power consumption for agriculture, we assume that 95% of the wells will be electrified by 2030, translating into an increase in electricity consumption by the sector to 70 TWh/y. As for street lighting and public (e.g., governmental buildings, schools) electricity demand (Figure 7F), assuming complete access has already been provided, future changes in power consumption for these uses are likely to follow the same trend as with the population growth. As a result, we estimate that the power demand for public uses and street lighting will reach 44 and 5.5 TWh, respectively, by 2040.

Figure 8. Historical data and projected electricity consumption for major users (1990–2040). Circles show per capita electricity consumption.

Future Electricity Supply

Based on the above projections for electricity consumption and the current capacity deficit of approximately 6 GW, Iran’s nominal generation capacity should reach 130 GW by 2040, suggesting that, on average, an annual capacity addition of 2.2 GW should be targeted in the meantime. However, due to the expected decline in annual demand growth from 6.8 to 3.8 TWh by 2040, the need for annual capacity addition during this time will accordingly decrease from 3.0 to 1.3 GW.

In the following subsections, we first evaluate the economics of alternative options for future additions to Iran’s power generation capacity. Subsequently, we propose a roadmap for future developments in Iran’s power sector in which the results of the abovementioned analysis, along with Iran’s power generation landscape and resource availability, have been taken into account.

1) Existing Power Plants Upgrade and Retrofit

Iran has considerable potential for augmenting its power generation capacity by adding steam turbines to its existing large-scale simple cycle gas turbine plants and, to a lesser extent, through retrofitting old steam plants. We estimate that the former change can bring about a total of 8.7 GW additional capacity while the latter has a relatively small potential of adding 1.3 GW to Iran’s nominal capacity (Figure 9). Upgrading all simple cycle gas turbines to a combined cycle would save 43 mcm/d compared to the baseline scenario of constructing new combined cycle plants, resulting in a marginal electricity production cost of approximately 0.8 ¢/kWh.

Retrofitting of steam power plants in Iran is primarily driven by the need for replacing major parts of such plants that have long passed their normal lifetime. As such, the slight fuel saving (about 6 mcm/d) achieved upon retrofitting such plants can be regarded as a side benefit.

Figure 9. Cumulative increase in nominal power capacity and natural gas saving through addition of steam turbine to the existing simple cycle gas turbine plants and retrofit of old steam power plants.

2) Construction of New Combined Cycle Plants

Construction of new combined cycle power plants (or gas cycle plants that are to be upgraded to combined cycle) constituted the large majority of Iran’s new capacity additions over the past ten years. Moreover, given the increasing share of natural gas in the domestic energy mix in Iran, the combined cycle plants will likely continue to be the predominant fossil capacity additions in the foreseeable future. According to the US Energy Information Administration (EIA) [20], the average capital, fixed operations and maintenance (O&M), and variable O&M costs for a conventional combined cycle power plant with a nominal capacity of 620 MW are $917/kW, $13.2/kW/y, and $3.6/MWh, respectively. Based on these figures, while excluding the cost of fuel and assuming a plant lifetime of thirty-five years, the cost of electricity generation by combined cycle power plants is estimated at about 0.8 ¢/kWh. In order to estimate the true cost of fuel for marginal electricity production at a given time, the opportunity cost for the marginal consumption of natural gas should be taken into account. As discussed in the previous section, the direct revenue from natural gas for the expandable end uses in Iran varies between $34,000 and $270,000/mcm, which would translate to between 0.7 and 5.5 ¢/kWh for combined cycle plants. As a result, the true cost of marginal electricity generation at a discount rate of zero by new combined cycle power plants varies from 1.5 to 6.3 ¢/kWh depending on the maximum economic return from the alternative uses of natural gas available at the time.

3) Renewable Energy

In general, the cost of renewable power mainly depends on the following factors:

• Inherent potential of the location (e.g., solar irradiance, wind speed)
• Project size and technology
• Remuneration policy
• Cost of capital

As discussed in the introduction, Iran has a high potential for renewable energy. Based on the map of solar irradiance (Figure 3), we estimate that the power generation potential of a typical high-yield location with a reasonable access to the grid in Iran to be 1,650 kWh/kWp, which is higher than the average power generation potential of the largest solar projects commissioned in the past two years in the world (see Appendix D). We considered a range of $700 to $1,100/kWp for the CAPEX and $15/kWp for the annual OPEX of solar power generation. Besides the unprecedented cost reductions that have occurred in the solar sector, the cost of power generation from wind has also declined by 60% in the past six years [21]; the capital cost of onshore wind farms currently ranges from $1,250 to $1,700/kWp [21]. In this analysis, we assumed that the CAPEX and annual OPEX of large-scale wind farms will be $1,300 and $40/kWp, respectively, while the capacity factor (CF) varied in the range of 30 to 50%.

Iran currently uses a feed-in tariff (FIT) mechanism to remunerate renewable energy generators. Due to reasons outlined below, we have instead used the information compiled from recent large-scale solar and wind tendered projects to estimate the range of values for the future cost of renewable energy. In general, using tenders (competitive bids) for large-scale renewable energy projects has proven to be an effective cost-reduction strategy as it allows governments to grant contracts to the best-performing technology [22]. As such, many countries have changed their remuneration schemes for large-scale projects from FIT to tenders and thereby have reduced their power purchase agreements to close to (or even lower than) the cost of electricity from fossil fuels (see Appendix D). We envision that Iran will follow suit in a few years and change its renewable energy remuneration mechanism to tender-based contracts.

Figure 10 shows how the internal rate of return (IRR) varies with the capital cost and PPA for solar and wind projects. In this figure, the horizontal lines indicate Iran’s total equity risk premium (ERP), which now is 11.2% [23]. The ERP represents the bare minimum internal rate of return that would potentially attract foreign investments.

As shown in Figure 10, an internal rate of return of 20% which is typically required to attract investment in Iran, would correspond to a levelized cost of electricity (LCOE) of from 9.5 to 14.3 ¢/kWh for solar power. In a hypothetical case where an internal rate of return of 11.2% would be sufficient for investment, the LCOE will decrease to 6.0 to 9.0 ¢/kWh for solar power. Similar analysis on the economics of wind power reveals that minimum PPAs of 7.0 to 11.5 ¢/kWh and 4.5 to 7.5 ¢/kWh are required to obtain IRRs of 20% and 11.2%, respectively.

Figure 10. Changes in the internal rate of return (IRR) of solar (left) and wind (right) projects with power purchase agreement (PPA) and unit capital cost for solar and capacity factor (CF) for wind. The horizontal lines show the present value of total equity risk premium (ERP) for Iran delineating the bare minimum return rate for attracting foreign investors.

Trends in Future Developments

Our demand forecast model showed that from 2017 through 2040, Iran will need to add a total of 54 GW of gross power generation capacity at annual rates of 3.0 GW at the beginning (i.e., the next few years) and 1.3 GW as 2040 approaches.

Comparing the above three pathways through which Iran can meet its future electricity demand, it becomes apparent that upgrading the existing simple cycle gas turbine plants to combined cycle leads to levelized electricity costs of less than 1 ¢/kWh and therefore will be given the highest priority. This modification will add roughly 8.7 GW to Iran’s gross power generation capacity. As many steam turbine plants have passed retirement age, their retrofit and modernization seem to be inevitable. The (small) efficiency gain to be expected through this process can add up to 1.3 GW to Iran's gross production capacity.

The above two low-cost and/or mandatory changes, however, can bring about only 10 GW of Iran’s roughly 53 GW projected demand growth through 2040, indicating that Iran’s additional need for energy should be met via installation of new combined cycle plants, with a potential contribution from renewable energy sources. To evaluate the viability of renewables we assumed two capital source scenarios:

• Publicly funded projects. Assuming that the Iranian government provides the capital for both types of power generation projects, large-scale renewable power projects will generate electricity at a levelized cost of 3 to 4 ¢/kWh, whereas LCOE from new combined cycle plants in Iran will range from 1.5 to 6.3 ¢/kWh depending on the best opportunity available for an alternative use of natural gas. Despite the promising levelized costs offered by renewable energy plants, their overnight capital costs per unit of actual power capacity ($3,700 to $5,900/kWa) are significantly higher than those of gas-fired power plants (about $1,000/kWa), posing a major barrier to their development in Iran, where public funds are currently very scarce. Nevertheless, if the economy allows for such investments in the future, the large-scale renewable energy projects will be feasible only if the alternative use of the unused natural gas can be sold at, or results in an avoided cost of, $150,000/mcm or higher. Currently, using natural gas for CNG fleets, for export to neighboring countries, and for reinjection into mature oil fields for improved recovery (although subject to some uncertainties) satisfies this condition.
• Privately funded projects. Assuming a required return rate of 20%, the private sector would need a minimum PPA of 7 to 14 ¢/kWh in order to consider investing in renewable energy in Iran. With the same required rate of return of 20%, the levelized cost of electricity generation (excluding fuel costs) from a gas-fired combined cycle power plant will be close to 2.8 ¢/kWh. Therefore, for a privately funded renewable energy project, the economic return (or the implied avoided cost) from the alternative uses of the displaced natural gas should exceed $200,000 to $550,000/mcm in order to justify a premium sum of 4.2 to 11.2 ¢/kWh for renewable electricity.

Based on the abovementioned analysis and considering the actual revenues (or avoided costs) associated with different end uses for natural gas, we conclude that utilization of renewable energy will be a viable option only in specific cases as outlined in Table 1.

Concluding Remarks

In this study, we evaluated the natural gas and electricity sectors in Iran and projected their future supply and demand trends until 2040. Our analysis showed that natural gas production in Iran will continue to grow at high rates to reach 960 mcm/d by 2021, beyond which the net year-over-year growth rate is expected to decline to values as low as 5 to 10 mcm/d. Natural gas exports to neighboring countries are likely to rise to 100 mcm/d levels within the next few years. But any further expansions in export, particularly to the European Union, seem infeasible. The residential and commercial demands for natural gas have almost reached a plateau because neither a major expansion in gas distribution grid nor a major increase in population seems plausible. The largest growth in natural gas demand will come from petrochemical and other industries and from the power sector.

Our analysis showed that from 2017 through 2040, Iran will need to add a total of 54 GW of gross power generation capacity at annual rates ranging from 3.0 GW in the near term to 1.3 GW at the end of the time period. Upgrading the existing power plants will add 10 GW capacity at a levelized cost of less than 1 ¢/kWh, while the levelized cost of marginal electricity generation by combined cycle plants ranges from 1.5 to 6.3 ¢/kWh depending on the opportunity cost considered for natural gas.

We also show that with a future levelized cost of less than 4 ¢/kWh, publicly funded utility-scale renewable energy (solar PV and wind) will become economically viable only if the selling price of displaced gas exceeds $150,000/mcm. Currently, the only uses of natural gas that satisfy this threshold requirement are transportation (CNG), gas export, and reinjection into oil fields. While gas export and reinjection have some growth potentials, the market for CNG vehicles seems to have become saturated. Hence, any further expansion would require a market stimulus such as an increase in the domestic price of gasoline.

The economic return (or the implied avoided cost) from alternative uses of displaced natural gas should exceed $200,000 to $550,000/mcm in order to justify a premium sum of 4.2 to 11.2 ¢/kWh for renewable electricity generation by the private sector. Among the major end uses of natural gas in Iran, only CNG vehicles and, with larger uncertainty, export of gas to neighboring countries might surpass such a threshold.

Acknowledgments

The authors would like to thank Dr. Mohsen Mesgaran (Stanford University) and Dr. Behdad Aminzadeh (Chevron Corporation) for their help throughout the work.

References

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Methods and Data

All data presented in this study have been collated from public sources available online. In this study, marketed natural gas refers to the sum of natural gas refinery outputs and the untreated portion of the gas that is injected into oil fields for improved recovery. Future projections for natural gas production are based on the existing fields as well as the future production augmentations from the development of greenfields and brownfields (i.e., already developed fields). In order to estimate the added value per unit natural intake by petrochemical plants in Iran, we first subtracted the capital and operation costs of petrochemical plants from the total revenue of the petrochemical sector to obtain a gross profit. We then calculated the natural-gas equivalent of all hydrocarbon inputs to the petrochemical plants, both as fuel and feedstock—i.e., natural gas, ethane, NGL (natural gas liquids), condensates, naphtha, kerosene, and platformate—based on their relative economic value. Finally, we estimated the added value of the petrochemical industry per unit natural gas intake by dividing the gross profit by total natural gas equivalent input. See Appendix C for further details.

Solar irradiance was obtained from Vaisala 3TIER Services Global Solar Dataset [11], which provides average annual global horizontal irradiance (GHI). The dataset has a spatial resolution of 3 km and was created based on more than ten years of hourly GHI data from visible satellite imagery observations via the broadband visible wavelength channel. Wind speed data were obtained from Vaisala 3TIER Services Global Wind Dataset [12], which contains wind speed data at 80 meters above the ground at a 5 km resolution. The values are based on over ten years of hourly data created through simulations and then validated via comparison with data obtained from several thousand ground measurement stations.

The CAPEX and OPEX values for conventional and alternative power generation methods were obtained from [20, 21]. Discounted cash flow (DCF) analysis was implemented to estimate the internal rate of return for different power purchase prices. The country equity risk premium was obtained from [23]. In this study, we used the levelized cost of electricity (LCOE) to evaluate the viability of power generation from different sources. LCOE is calculated as

where C. is the net expenditure in year t, E. is the electrical energy produced in year t, r is the discount rate and n is the expected lifetime of the power station.

For currency conversion, a dollar-to-toman exchange rate of 3,800 has been uniformly applied throughout this study.

Appendix A: Iranian Natural Gas Refineries and Future Projects

Appendix B: Iran's Gas Exports to the European Union

As natural gas production rates continue rising in the South Pars field, Iran is in a position to explore lucrative exports to regional and international destinations. This is especially true as dropping oil prices affect the country’s federal budget. As discussed earlier, we forecast that Iran’s total exports of natural gas to Turkey, Iraq (Baghdad and Basra), Oman, and Armenia will reach 100 mcm/d levels within the next five years. In this section, we briefly review the main factors affecting potential Iranian gas exports to the European Union (EU).

While the EU is not now importing any natural gas from Iran, the potential for long-term opening and developing of trade patterns has been under consideration by both sides. The recent nuclear deal between the West and Iran could potentially prove to have implications beyond the Middle East peacemaking process by affecting the European Union’s tactical decision to slowly uncouple from Russia’s gas supply. A partial replacement of Russian supply with Iranian gas would not only diversify EU’s energy mix but also help reduce gas import prices. However, for such a linkage strategy between Europe and Iran to be successful, both partners must make long-term concessions and commitments. As a prerequisite to such deals, the European Union must agree to a substantial long-term contract on gas shipments from Iran, including investments in expanding Iran’s production capacity and completing the required pipeline.

As far as the transport infrastructure is concerned, Iran’s gas grid is not fully connected to Europe but does benefit from a partial connection to Turkey via the Tabriz-Ankara pipeline. This pipeline transports gas from the South Pars gas field to the city of Bazargan at the Turkish border. One option is the proposed Persian Pipeline, a 3,300 km network which would cross Turkey before reaching Italy. From there it would divide into southern and northern sections, delivering gas to Germany, Austria, Switzerland, France, and Spain.

According to the German Federal Office of Economic Affairs and Export Control [24], Germany’s average gas border prices in 2015 and 2016 were $213,000 and $160,000/mcm, respectively. Such low prices would barely cover the costs of extraction and transportation of gas from southern Iran to Europe and therefore are far from being economically viable for Iran. As shown in Figure 6, many uses for natural gas in Iran would already yield higher or comparable revenues at significantly lower costs. Thus, we believe that a minimum gas selling price of $350,000/mcm is required to trigger Iran’s interest in exporting gas to the EU. Besides economic considerations, given the strong political, economic, and military ties between Iran and Russia, it seems unlikely that Iran would want to undermine its strategic relations with Russia in the foreseeable future for such small economic benefits.

Appendix C: Brief Economic Analysis of Petrochemical Industry in Iran

In 2015, Iran produced 25.3 million tons of petrochemicals with a total market value of $14.5 billion [25] from forty-nine petrochemical plants. On average, the market values of Iran's petrochemical outputs were $573/ton and $708/ton in 2014 and 2015, respectively [25]. Table C-1 lists the hydrocarbon intake of these plants encompassing fuel and feedstock uses. Using global commodity prices, an equivalent amount of natural gas based on the market value for each of these resources was first estimated and then summed to give a total natural gas-equivalent intake, which turned out to be 177.7 mcm/d in 2015. Therefore, Iran obtained gross revenues of $224,000 per mcm of natural gas-equivalent input to its petrochemical plants in 2015. By comparison, it can be inferred that in 2014, when the average petroleum prices were higher, gross revenues generated by the Iranian petrochemical industry were $276,000/mcm of natural gas-equivalent. Here, we use an average value of $250,000 for the market value of Iran’s petrochemical products per one million cubic meters of natural gas-equivalent consumption (as feedstock and fuel together).

In order to estimate the added value of natural gas within the Iranian petrochemical sector, one has to subtract the capital and O&M costs (fixed and variable) from the gross revenue. To this end, we herein use methanol plants as an example. A typical methanol plant produces 1,020 tons of product per mcm of natural gas consumed [26]. The capital, fixed O&M costs, and variable O&M costs of a methanol plant per million cubic meters of natural gas input are $137,000, $24,000, and $10,000, respectively [27], resulting in a total cost of $171,000/mcm gas input (excluding the costs of fuel and feedstock). Assuming a FOB price of $440/ton for methanol, in rough terms, the capital and O&M costs of a methanol plant are equal to 38% of its gross revenue. Extending the above analysis across the entire industry indicates that, of the $250,000 gross revenue per mcm of NG-equivalent input, about $95,000 is attributed to capital and O&M costs; hence, $155,000 is the gross added value per mcm of natural gas-equivalent input to the petrochemical plants in Iran. We note that this value does not represent profit, as the costs of feedstock and fuel have not been taken into account.

Appendix D: Economics of Renewable Energy in Iran

We estimated the average capital and operational costs for solar power plants based on the information compiled from utility-scale projects contracted globally in 2015/16 (Table D-1).

Annual electricity generation (kWh/kWp) was estimated using geospatial tools provided by USA National Renewable Energy Laboratory (NREL) [28]. The discount rate of these projects (which depends on a country’s risk premium and financing resources) was assumed to be equal to the respective country’s equity risk premium as provided in reference [23]. The CAPEX and OPEX of onshore wind farms in 2016 were reported at $1,250 to $1,700/kWp, and $40/kWp, respectively [21]. In this analysis, we assumed that the CAPEX of large-scale wind projects in Iran was $1,300/kWp, while the capacity factor varied between 30% and 50% to obtain a range for the future LCOE of wind power.