Romania: Natural Gas – Facing a Pricy Winter (EPG)

Regardless of the outcome of the heated debate impacting future offshore gas projects, Romania will face winter 2018-2019 with the same “source mix” it has had in recent years: a substantial level of domestic production, storage withdrawals to fit the demand profile, as well as imports, especially in very cold days, when the first two fail to suffice. In the past three years, the game changer was the price, already at Lei 120/MWh for month-ahead October (compared to Lei 73.06/MWh last year), [1] as well as the development of a short-term market: standardized day-ahead trades gained momentum last month and will likely intensify, on account of the fickle autumn weather and the intensifying cold.

This analysis details the relevance of each component in the mix, explaining how gas shortages are usually dealt with, and presents the next regulatory steps essential to cover gas demand.

“Ancient” history

Historically, to distinguish between local and imported gas, it is helpful to have an overview of the past 30 years, as shown in Chart 1.

Before sourcing, one first notices the immense drop in demand, from 400 TWh in the late 1980s to 120-130 TWh in recent years [2]. The collapse of massive industrial platforms and, to a smaller extent, energy efficiency measures at all levels (industry, thermal plants, district heating, residential insulation etc.) have brought gas demand to a third of what it once was – and a third of what the gas transport system was designed to carry (a key issue in balancing operations, as will be seen further on) [3].

When it comes to local vs. import sources, two aspects are obvious:

  • Local production was way higher in the 1980s than it is now. In fact, most of today’s active gas fields were started in that period, and Chart 2 clearly shows the difference between a “young” field, where pressure is so high that extraction is nearly effortless, and a “mature” field, with little gas left, requiring costly enhanced recovery measures, and with much lower daily output. With scarce investments in the development of new fields, production has been gradually decreasing in the past 20 years.
  • Despite high production, imports in the late ‘80s and early ‘90s were very high. Not only was the geopolitical context different, but demand was too high to cover from domestic sources.

Closer to present day, Chart 1 shows that the share of import has dwindled, leading many to state that Romania is nearly independent in terms of natural gas supply. However, even in recent years, because of the limited local potential, the seemingly unimportant gas imports play a vital role in keeping pipeline infrastructure operational during cold spells.

Recent developments

One should acknowledge the recent years’ gas demand configuration, and the way it was met. Charts 4 and 5 in the Annex show these two evolutions at national level, between October 1, 2014 and September 30, 2018 (the last four gas years). A few points worth mentioning are detailed.

In terms of demand, the daily maximum, for days of frost and/or blizzard, is around 760 GWh, just above 70 mmcm (million cubic meters). This can be compared to the minimums of summer days, when gas is no longer used for heating, and the volume goes towards 150 GWh, about 14 mmcm. The “weekend effect” (inactive factories) is also visible on the gas demand chart.

At yearly level, roughly 90% of domestic production is split 50-50 between Romgaz and OMV Petrom, with the rest covered by Amromco, Stratum and other smaller producers [4]. Total output used to have 300 GWh/day as a solid benchmark volume, totaling about 110 TWh/year [5]. However, recent years have showcased the amplitude of swing procedures:

  • In early 2016, low crude oil indices had taken oil-linked gas import prices below Romanian production, even below Lei 70/MWh (see Chart 2 in the Annex), which led many suppliers to off-take more imports, even in warm months. With contracts reduced, producers temporarily shut down some fields, taking daily output to an unexpected 220 GWh in some days. Even Q4 2016 saw much higher import levels than in previous years. And with imports still relatively cheap, suppliers’ interest in imports remained high in winter 2017-18. Production levels returned to 300 GWh/day in Q4 2017.
  • However, as of Q2 2018, production has settled around 275 GWh/day, despite market prices constantly increasing (from Lei 80 to 110/MWh from spring to autumn).

Concerning storage, ANRE realized long ago that production does not cover winter needs and it is unwise to leave all excess demand to short-term imports. Therefore, it established a storage obligation [6] – i.e. every year, it mandates a certain quantity that each supplier must inject (or buy in storage) during summer. More specifically, ANRE sets a market-wide obligation at 25% of previous winter (October-March) consumption. The split per supplier is made by market share. If at the beginning of the cold season, usually November 1, a supplier does not prove it has the obligation volume stored, it is fined from 5 to 10% of its turnover [7]. Such a harsh penalty ensures market-wide compliance.

Because of the low market liquidity and constantly increasing prices, suppliers lived the summer of 2018 intensely, seeking volumes to meet their storage obligation. From a commercial point of view, suppliers are reluctant to store a lot, since each stored MWh costs the initial purchase price (from production or import) plus regulated storage tariffs (injection, rent and withdrawal), which means that withdrawn gas could be more difficult to sell, even during winter. However, with prices still going up, this winter it is likely that stored gas, particularly from volumes bought in early summer, will be cheaper than imports, possibly even than local production. As a side note, the compelling storage obligation also helps producers keep summer outputs at the same level as winter ones, thereby reducing their operating costs.

The maximum expected storage output is at 345 GWh/day (32 mmcm)[8], but this is the value “when planets align”, that is, when the transport network is at optimal pressure parameters, and is more likely in early winter, when facilities are still “full.” There are six storage facilities operated by Depogaz (part of Romgaz), with a total capacity of 2,700 mmcm, and one storage facility operated by Depomureș (part of the ENGIE group), with 300 mmcm capacity. All seven are underground facilities hosted in depleted gas fields, therefore, the more gas in store, the higher the underground pressure, the higher the daily output.

Concerning imports, the daily chart shows that gas brought in via Ukraine is still dominant, with last winter’s maximum at 190 GWh/day (18 mmcm), from a total technical capacity of 380 GWh/day (260 at Isaccea, near Tulcea, and 120 at Medieșu Aurit, near Satu Mare) [9]. Imports via Hungary, through the Csanádpalota (Arad-Szeged) interconnector, only picked up in Q1 2018, reaching 35 GWh/day, while the Giurgiu-Ruse Bulgarian link was inaugurated last year, with flows below 10 GWh/day so far.

Taming the line pack

At this point, it is important to consider the delta between the hypothetical peak consumption in a very cold day 760 GWh, and maximum local sources, 300 GWh (production) + 345 GWh (storage) = 645 GWh. In such a day, the 115 GWh “gap” can only be covered by imports.

While the cross-border flows mentioned above would seem to suffice, such days bring cold weather not only in Romania, but also in neighboring countries. It just so happens that the pipelines from which Romania imports gas at Isaccea go further South, fueling heating demand in Bulgaria, Turkey and Greece as well. These countries will likely need large volumes of gas as well. This is why, in such a day, imports can either become very expensive, or downright limited. When suppliers are left without sufficient sources to satisfy demand, the Romanian market is on a deficit. This is when the transport network line pack level becomes crucial.

Gas volumes from all three types of sources (production, storage withdrawal and import) are “guided” towards their destinations (consumption, storage injection, or export) through the intricate network of transmission pipelines, owned operated by Transgaz, the state-controlled TSO (Transport System Operator). Like any TSO, Transgaz must constantly keep a certain volume of gas in its pipelines (the so-called “line pack”) to ensure a pressure that allows the gas to circulate and reach consumption/injection/export points. This volume can be monitored hourly on the Transgaz public website [10]. There one can see that:

  • The volumetric interval which ensures optimal pressure is 40-42 mmcm.
  • Outside those values, “normal” pressure (with reduced TSO operations required) is attained within the 38-44 mmcm marks.
  • Anywhere between 33-38 and 44-46 mmcm, line pack levels can prompt the TSO to take preemptive action, such as withdraw gas from its intervention stock (if volumes/pressures become too low) or inject gas in storage (if volumes/pressures become too high).
  • When the line pack increases above 46 mmcm, usually during oversupply situations (unexpectedly warm weather, like New Year’s 2018), Transgaz can choose between selling gas on short-term markets and, if no trades are closed, evacuate the surplus via storage injection. Otherwise, the pipelines can suffer damage on account of critically high pressure.
  • The grim scenario is when the line pack creeps below 33 mmcm. This happens when all sources maxed fail to meet demand, Transgaz is unsuccessful in buying emergency gas on the market, and consumption ends up drawing from the fourth type of source (which should not be used as such), the pipeline gas crucial in maintaining system pressure. A protracted drop below 33 mmcm can lead to gas supply disruptions, leaving most or all consumers, from households to large industrials, with little or no gas. The even bigger issue is that, theoretically (though this has never really happened so far), a full-fling collapse of the transport network would require days, even weeks, to overcome and restore normal flows.

Handling a gas supply crisis

In the most recent severe cold wave (late February to early March 2018), on February 26, the line pack dropped from 45.8 mmcm to 38.0 mmcm in 24 hours. That means 7.8 mmcm or 83 GWh (12% of that day’s 700 GWh demand) were not available on the market and were drawn from the pipelines to be consumed. The even bigger issue was that the cold would last for another two days, in which the line pack continued to drop. As it neared the dreaded 33 mmcm mark, there was a special meeting of high Government and ANRE officials, top brass representatives of Transgaz, producers, storage operators, as well as large consumers. The latter are key in such gatherings – when the cold persists and no more sourcing is available, the only measure to avoid network issues is to cut demand.

A first precaution is to prompt all consumers that can switch from gas to fuel oil to do so. If this is not enough, large industrials and gas-fired power plants are simply asked to temporarily shut down. This is because there is no regulation specifying (naming) which large consumers are interruptible. In this past winter’s episode, while no official report was issued, gas demand was reduced following the meeting, meaning that either a big industrial platform, or a power plant agreed to minimize gas offtakes from the network.

Ways to prevent shortages

As we can see, three days of no more than 10% market-wide deficit are enough to bring about special measures. This is why imports, though seemingly tiny at yearly level, and barely present on the chart in the winters of 2014-15 and 2015-16, have proved essential during “frostbite” periods, helping to avoid, or at least postpone, crises like the one mentioned above. Should this alternative be discarded, demand reductions would become common practice.

Imports will cease to be the emergency solution once either production output increases (especially through investments in new fields, onshore or offshore), or storage capacities are expanded, either by adding compressor stations, or by creating new facilities. Such measures would ensure higher daily availabilities of local sources. However, they would also come with a cost: one the one hand, producers would require a stable fiscal regime for the new projects. On the other hand, storage is a 100% regulated activity in Romania, meaning that yearly tariffs are set by ANRE and recognition for consistent investments would mean higher bills for the end consumers. Both situations require delicate political decisions, which need to be balanced.

Naturally, should the massive Black Sea projects start, the cold spells will no longer see import as the sole savior. In fact, the large offshore volumes could also change the business model of storage operators, which would see a reduced use of their facilities, due to abundant current production and possible discard of the storage obligation. In any case, these projects will not come online before 2022.

This is why, until new volumes are brought to the market, the proper functioning of the Romanian gas transport network and the market itself are likely to be dependent on imports – not only from a volume point of view, but also through their influence on prices.

The price factor

Despite abundant production and relatively high storage capacities, Romanian market prices are influenced by imports. Against the background of feeble infrastructure progress, in terms of interconnectors and compressor stations, gas brought in via Ukraine dominates this landscape. Note that, whenever gas from Hungary or Bulgaria becomes cheap enough to attract Romanian suppliers, one can assume it is also gas originating from Russia, brought via Ukraine into Hungary, or which initially transited Romania via Isaccea-Negru Vodă to Bulgaria. Other origins are probable only in special conditions, and limited by the capacity available or price, depending on market correlation: gas from the Austrian hub at Baumgarten is rarely at a tempting price to bring all the way to Romania (CEGH day-ahead traded in early October at €27,8/MWh, meaning Lei 130/MWh [11]), Hungarian and Bulgarian production are very low, and more remote sources cannot be cheap, as transport tariffs in transited countries would greatly augment the price.

Imports via Ukraine are often based on long-term (decades-long) contracts, with prices traditionally linked to crude oil or, more often, petroleum products, such as fuel oil, diesel etc. This seems pointless at present, but it used to make sense in the past – indeed, back in the 1960s and ‘70s, the alternatives to natural gas for heating or power generation were fuel oil and diesel, and so it was important for gas prices to follow trends of competing products.

In any case, because of the collapse of crude oil quotes in mid-2014, this link with oil markets from most long-term contracts in Romania is what made gas imports really cheap in 2015-2017 (roughly Lei 70-80/MWh, even in winter), bringing local production prices down as well. With oil prices rebounding earlier this year, the same link has brought imports, and consequently local prices, in the three-digit numbers for this autumn. The newly-inaugurated day-ahead market, hosted on OPCOM[12], and soon to be implemented on BRM (the Romanian Stock Market) as well, sees trades around the Lei 100/MWh mark as of early October. By December, one can expect an average of Lei 120/MWh. For reference, March 2018 month-ahead was at Lei 78.78/MWh, while the highest 2018 price was Lei 147.46/MWh [13], for two trades on March 1 and 2.

A special mention is the expected replacement of oil-linked prices with hub-linked prices, common practice in Western markets. While CEGH is usually too remote for a correlation, the Romanian standardized indices will soon provide viable and transparent price references.

What lies in store

Building on the previous issues, here are the aspects relevant in balancing supply and demand:

  • Based on EU Reg. 1938/2017[14] for the security of gas supply, the Ministry of Energy should prepare and publish the yearly winter contingency plan – the set of actions to be taken to prevent or mitigate the impact of supply shortages. However, as of early October, no announcements have been made on this topic.
  • Also based on EU Reg. 1938/2017, a draft ANRE initiative is out for debate, aiming to establish which are the protected consumer segments, which should be exempted as much as possible from gas curtailments, in the event of supply crises. These will likely be residential consumers, thermal plants for household heating, buildings of strategic or social importance (health, education, defense etc.) etc. This will also be a first step in settling which consumers can be deemed interruptible – the kind of rule mentioned above, which could clearly specify whose supply can be cut off to relieve the system. As of October 4, debates on the draft are over, and a final document is to be published in the coming weeks.
  • Short-term trading is picking up, with day-ahead transactions now closing regularly. These will be key price references, not only for balancing, but for longer term trades as well.
  • An ANRE Order soon to be published will set the rules for trading on centralized markets, particularly the trade obligation percentages for suppliers. While these could be key in shaping a transparent market (albeit forcedly), this rule could impact decisions for major producers in the long run: the potential Black Sea gas field operators are reluctant to sell a percentage of their eventual output (40-50%, or even more) at the Romanian VTP, as this could limit their free market horizon.
  • Radical changes have been made to the Network Code[15], the keystone document regulating all technical and commercial operations in the natural gas transport network. Historically, this document drove the Romanian market from monthly balancing, in which a supplier that recorded a deficit one day could offset it with an excess in the next day (although any imbalance is unwanted) to daily balancing, in which suppliers are applied a penalty for the imbalance in a day, regardless of their behavior in other days. The main European references for this document are EU Reg. 312/2014 [16](BAL NC, the volumetric balancing rules), EU Reg. 715/2009 [17] (CAM NC, regulating access to transport) and EU Reg. 703/2015 [18] (INT NC, for transport network interoperability and data exchange).

The most recent changes toughen penalties for supplier imbalances, taking prices to [market price] + 10% for any MWh of deficit and [market price] – 10% for any MWh of excess. This will prompt suppliers to make their forecasts more accurate. All the more interesting, since from the current gas year (from October 1, 2018), all suppliers in the market are mandated to become network users, that is, to sign a transport contract with Transgaz, as well as a balancing contract, to access the VTP for daily trading.

Another major update is the shift of the delivery location for most trades (particularly from production) in the Romanian VTP, which means delivery “inside” the transport network: the seller ships the gas until mid-way, and the buyer takes it from there and ships it towards its destination. This means capacity costs are split evenly between the two counterparties, a change from the traditional practice of suppliers buying “on the field”, at the entry of the transport network.

  • The ANRE-imposed forecasting methodology [19] for aggregate non-daily metered flows, which should be published and implemented by Transgaz in October, is still expected. It would mean intra-day and day-ahead forecasts that each supplier would receive on their non-daily metered consumers (mostly residential and small B2B), crucial data once the cold sets in, to help suppliers with short term balancing.
  • On medium term, a new methodology for cost recognition on supplying the regulated (residential) consumer segment was drafted and is up for debate until October 15. Its final form will apply in 2019, with necessary changes following Network Code updates and the launch of standardized short-term product trading, all of which will set new price references.
  • The Transgaz TYNDP (Ten Year Network Development Plan) for 2018-2027 [20] – apart from the BRUA pipeline and Black Sea gas accommodation, the TSO plan includes supporting additional storage capacities, led by Depogaz, from winter 2019 on.

While volume-wise no surprises are expected, winter 2018-2019 will be interesting to watch in terms of prices, depending on the time of arrival and frequency of cold waves.

Source: EPG

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