Oil price reporting agency Argus recently released a price assessment for a new grade of Permian crude oil. The grade, known as West Texas light (WTL), covers Midland delivered crude with a higher oil gravity (API) between 44.1 and 49.9. At the time of the announcement, Argus reported that WTL was trading at a $1.40 to $2.00 discount to West Texas intermediate (WTI) Midland, a slightly heavier grade. DrillingInfo’s US oil production data shines a light on the origins of this emerging grade of crude.
US oil production has increased rapidly over the past several years as the combination of horizontal drilling and hydraulic fracturing allowed producers to unlock previously inaccessible resources. With these technologies, US exploration and production companies have transformed the Permian Basin in West Texas and eastern New Mexico. Previously considered a past-its-prime backwater, it is now the world’s most prolific source of oil, surpassing even Saudi Arabia’s famed Ghawar field. Production in the Permian increased from less than 1 million barrels per day in December 2010 to over 3.8 million bbls/d by December 2018.
As production in the Permian increased, lighter crude oils, those with a higher API, were mixed with heavier crudes to create a blend with specifications mirroring that of WTI. According to Argus, the supply of these very light crudes has now outstripped the capacity to blend them, forcing pipeline operators such as Enterprise Products and Plains to segregate these barrels and ship them in batches based on classifications shown in the table.
To gain additional insight on the growth of WTL production, we turn to DrillingInfo’s well level production data. Regulators require that in addition to production data itself, oil and gas producers must also report the results of initial tests performed on the oil and gas stream extracted from a well. One element of these initial tests is the API of the crude being produced. This data can be slightly lagged, so the most current months are more likely to be missing and will fill in over time. Despite that limitation, the data provides useful insight into the growth in production of these lighter crudes as well as the variation of API across the Permian Basin. By slicing Permian production according to the specifications laid out in the Enterprise tariff shown above, we can track the growth in light crude oil production from the Permian Basin. In December 2010, the Permian was producing less than 40,000 bbls/d of oil with an API between 44.1 and 49.9, the range specified as WTL. By the end of 2018, WTL production was up to nearly 500,000 bbls/d, with another 150,000 bbls/d of oil and condensate with an even higher API also being produced. Production in the WTI range had grown from roughly 460,000 bbls/d to more than 1.9 million bbls/d. The average API for wells with a reported test oil gravity has also been on the rise, increasing from 37 to nearly 41.5.
The Delaware Basin, one of two sub-basins within the Permian Basin, has been driving the growth in production of these very light barrels. As the chart below indicates, production from the Delaware tends to have a higher API than that of its neighbor to the east, the Midland. While API has increased for both basins since 2010, the Midland Basin has remained in the WTI range, while the average API in the Delaware Basin is now in the WTL range.
While both the Midland and the Delaware have seen tremendous growth since 2010, production from the Delaware has ramped up significantly since 2017, surpassing the pace of the Midland. As this pace has increased, the characteristics of the oil produced in the Delaware are altering the dynamics of the crude markets in the Permian.
The characteristics of the Delaware are evident in the well level data. Among wells with a tested API gravity, more than 30% of production came from those in the range of WTL. Around 50% of production came in the WTI range. In the Midland, production from wells that tested in the WTL range made up only 5%, while nearly 80% of production from wells was in the WTI range.
Drilling activity in the Permian indicates this trend towards higher gravity is likely to continue. According to DrillingInfo’s Rig Analytics, there are more than 260 rigs at work in the Delaware basin relative to the 200 or so rigs working in the Midland. With a greater number of active rigs, growth in the Delaware will continue to outpace that in the Midland. As this trend continues, it will result in even greater supplies of the already discounted West Texas Light crude oil coming to market relative to WTI.
Large amounts of discovered gas and substantial exploration upside provide an opportunity for the Eastern Mediterranean to become a significant exporter. With the region increasingly in the spotlight, due to a number of recent discoveries and acreage offerings, we are taking a closer look at the current E&P picture in the littoral states, and some of the challenges they face.
To date, eight exploration wells have been drilled offshore Cyprus, four of which have been successful. Noble Energy drilled one well in 2011 and one in 2013, discovering and confirming gas in the Miocene Tamar sandstones in the Aphrodite Field (estimated at 4.5 Tcf recoverable). Eni targeted the same play in Block 9 in 2014 and 2015 (Amathousa and Onasagorus), but both wells came up dry. In February 2018, the Italian company attempted to drill a further well on the play in Block 3 however, rig operations with the Saipem 12000 drillship were impeded by Turkish military vessels, which prevented the vessel from reaching the wellsite. A future return to the prospect by Eni has been muted.
Blocking the ship was the latest twist in decades-old feuds and overlapping, contested claims in the eastern Mediterranean. Turkey and its vassal state, the Turkish Republic of Northern Cyprus (TRNC), object to the Republic of Cyprus (RoC) drilling in waters that the RoC claims under international maritime law. The RoC ratified the U.N. Convention on the Law of the Sea (UNCLOS) in 1988 and proclaimed its EEZ, in conformity with UNCLOS, in 2004.
Turkey is the only member state of the U.N. that does not recognize the RoC, and it is not a signatory to the UNCLOS. In addition, Turkey considers that a recent agreement between RoC and Egypt, which ratifies the delimitation of their respective economic waters, is null and void.
Just before this hostile episode in the Cyprus-Turkey relations, Total and Eni had some success in chasing the Zohr play in the RoC EEZ. The Total-operated Onesiphoros West 1 well on Block 11 found non-commercial gas in September 2017, whereas the Eni-operated Calypso 1 NFW on Block 6 was announced as a gas discovery in February 2018. Calypso reportedly contains 6-8 Tcf (assumed to be GIIP); Eni plans an appraisal program.
Subsequently ExxonMobil in partnership with Qatar Petroleum, conducted a two-well back-to-back drilling campaign on Block 10 in late 2018/early 2019. While the first well in the campaign, Delphyne 1, failed to find commercial quantities of hydrocarbons, the second well was successful. Glaucus 1 was announced as a gas discovery, with quantities of natural gas estimated at 5-8 Tcf.
While there had been talk of another offshore bid round (the 4th licensing round), the Cypriot cabinet has decided to go a different route this time around. In early October 2018, it invited companies already licensed to explore offshore Cyprus to submit their expressions of interest (EOI) for Block 7 (Herodotus Basin). The invitation concerned companies with concessions bordering the open block, namely Eni (Blocks 6 and 8), ExxonMobil (Block 10), and Total (Block 11), which were given one month to submit their EOIs. Yiorgos Lakkotrypis, Minister of Energy, Commerce, Industry, and Tourism, stated that the government chose to offer the block in this way instead of another licensing round as, “there are particular geological reasons related to the Calypso discovery.” The Minster’s statement, and the fact the Calypso discovery is located in the SE corner of Block 6, suggest that the Calypso structure extends into neighboring concessions. Total and Eni submitted a joint application for Block 7 and negotiations regarding the award of an E&P sharing contract are underway.
Figure 1. RoC demarcated offshore blocks and exploration wells. Also shown are the RoC’s proclaimed and partly agreed EEZ (light blue line), the TRNC’s proclaimed EEZ and outline of demarcated blocks (red line), the outer limits of the continental shelf as claimed by Turkey (orange line), as well as Turkey’s offshore exploration wells.*
In Turkey, more than a dozen wells were drilled in the Eastern Mediterranean between 1966 and 2014. None of them were successful, apart from some oil and gas shows. While the shows suggest a working petroleum system, it is not a very good track record. However, it must be said that offshore exploration drilling has been limited to near-shore zones in the Gulf of Alexandretta and the Gulf of Mersin, leaving large areas unexplored.
In an effort to extend exploration in the Eastern Mediterranean, the Turkish state oil company (Türkiye Petrolleri Anonim Ortaklığı – TPAO) has conducted extensive seismic acquisition programs over the last few years. In 2013, TPAO bought an 8-streamer 3D seismic vessel from Polarcus (the “Samur,” rechristened the “Barbaros Hayreddin Pasa”). Since then, it has been acquiring masses of data in the Mediterranean and the Black Sea. In the Eastern Med, the vessel has concluded at least seven separate surveys, with another currently ongoing. Surveys have been acquired to the northeast, south, and southwest of Cyprus, parts of which cover disputed areas.
Turkish officials, keen on reducing the country’s energy imports, have stated on various occasions that the country would take steps toward exploring and drilling in the Mediterranean. TPAO acquired its own drillships, the “Deep Sea Metro II” (now renamed “Fatih”) in late 2017, and the “Deep Sea Metro I” (now renamed “Yavuz”) in late 2018. In addition, it signed a two-well contract with Rowan Companies for the “Rowan Norway” ultra-harsh environment jack-up rig.
In November 2018, “Fatih” and “Rowan Norway” commenced drilling activities, with the former spudding the Alanya 1 well, in the Gulf of Antalya, and the latter spudding the Erdemli North 1 well, in Gulf of Mersin. Erdemli North 1 finished drilling in January 2019 and Alanya 1 in mid-April. Results have not been announced so far for either well. The “Rowan Norway” subsequently moved on to the Kuzupinari 1 location at the entrance of the Gulf of Alexandretta.
Some reports suggest that in the future, TPAO will conduct drilling operations in contested waters around Cyprus. For the ultra-deepwater “Fatih” and “Yavuz” drillships with ratings of 3050m, the water depths in the Eastern Med present no problem, allowing them to drill on any of the demarcated Turkish or TRNC offshore blocks.
Turkey and TRNC signed a continental shelf delimitation agreement in September 2001. Turkey’s claim on the island’s EEZ partly overlaps with the RoC’s blocks 1, 4, 5, 6, and 7. Ankara also supports the TRNC’s claims over RoC’s Blocks 1, 2, 3, 8, 9, and 13, where the self-declared TRNC has demarcated Blocks F and G. Should TPAO start drilling in any of these areas, it could lead to a serious geopolitical – or even military – crisis.
After the conclusion in 2017 of the delayed First Offshore Licensing Round, Lebanon is looking ahead to the drilling of the first exploration well. A joint venture between Total (40 percent), Eni (40 percent), and Novatek (20 percent), the only bidding group in the tender, signed E&P Agreements (EPA) for Blocks 4 and 9 in February 2018. Subsequently, Lebanese authorities approved exploration work plans submitted by the Total-led consortium, paving the way for operations; drilling is expected to begin in Q4 2019.
Total’s stated priority is to drill a first well on Block 4, with a second expected to follow on Block 9. With regards to Block 9, the company said that the consortium is fully aware of the Israeli-Lebanese border dispute in the southern part. However, given that the main prospects are located more than 25km from the disputed area, exploration drilling on the acreage will have no interference at all with any fields or prospects located close to the southern border.
Following a once again delayed approval by the Council of Ministers, Nada Boustani Khoury, Minister of Energy, officially launched Lebanon’s Second Offshore Licensing Round in early April 2019. The acreage on offer includes Blocks 1, 2, 5, 8, and 10, which are located in three distinct major geological zones. Block 1 falls within the Lattakia Ridge zone in the NW of the EEZ, Blocks 5 and 8 are located in the deep Levant Basin in the SW, and Blocks 2 and 10 cover parts of the Levant margin in the NE and SE. The blocks have been chosen to offer a number of different play types, as each zone is characterized by different structural and sedimentological features.
As in the first bid round, interested companies will be required to form a consortium composed of three partners or more, with at least one prequalified as operator. Companies will be able to choose their partners and prepare their bids, which have to be submitted by January 31, 2020. Once bids are submitted, the LPA will evaluate them and prepare a recommendation to the Minister of Energy and the cabinet. Negotiations with successful bidders and subsequent awards are currently planned for late March 2020 and early April 2020, respectively.
Figure 2. Lebanon’s exploration and bid blocks.*
Following several offshore gas discoveries in Israel between 2009 and 2013, current activity is focused on bringing the discovered resources onstream. Noble Energy’s Tamar Field (~10 Tcfg 2P) is the only producing offshore field, with Leviathan (~12.5 Tcfg 2P), also operated by Noble, currently under development. Leviathan’s first phase is more than 80 percent complete, on track to deliver first gas by the end of 2019.
Plans are also in place for the development of the Karish and Tanin fields. Operator Energean’s Field Development Plan (FDP) envisages a two-phase approach, with the Karish Field being developed first. The FDP includes the drilling of three development wells at the Karish Field and the installation of a new FPSO around 90 km from the shore. Development drilling started in March 2019, and first gas is planned for 2021. In a second phase, the Tanin Field development will follow, with the drilling of six wells. These will also be connected to the FPSO.
In terms of exploration, Energean is the only operator currently conducting exploration drilling.
In April 2019, it announced that its Karish North near-field exploration well has made a significant gas discovery in the Tamar B and C sands and the well is being deepened to test the hydrocarbon potential in the D4 horizon. Initial gas-in-place is estimated between 1-1.5 Tcf. Energean has drilling options for six further wells in its contract with Stena Drilling. The company has mapped various prospects and leads on the Karish and Tanin leases, as well as on the five exploration blocks it was awarded the First Offshore Licensing Round.
Further drilling in 2019 may be carried out by EDF subsidiary Edison, which operates the 399 Royee exploration license along the border with Egypt. While the first well on the acreage has been postponed on a number of occasions, Delek Drilling’s recent decision to acquire a 24.99 percent stake in the block may give the endeavor renewed momentum. However, drilling will have to start soon, as the license is only valid up to April 14, 2020. At that point the license will have reached its maximum term of seven years.
Israel’s Second Offshore Bidding Round (OBR2), launched in November 2018, may result in additional exploration activity in the country’s EEZ. The acreage offered for bidding in OBR2 includes 5 Zones (A to E) located south of the large gas fields presently being developed offshore Israel. Zones A, B, C, and D include four blocks each, while Zone E includes only three. Each block measures up to 400 sq km. Most of the area offered for bidding was held by various operators in the past, which acquired seismic data and developed exploration prospects that have not been drilled. The closing date for the submission of bids is June 17, 2019. Following a relatively timid response in the First Offshore Bidding Round, with only two companies submitting bids, Israel hopes for better participation this time. ExxonMobil is rumored to have expressed an interest.
Figure 3. Israel’s exploration and production licenses. The Second Offshore bid round zones consist of 19 blocks.*
As the most mature offshore area in the East Mediterranean, and with gas production in the Nile Delta Basin since the 1970s, the focus in recent years has been the ambition of turning the country into the center of an Eastern Mediterranean gas hub. It has not been smooth sailing, however. The country had been in a net gas deficit since 2014 and began importing LNG in 2015. The two LNG export terminals on the Mediterranean coast, Idku and Damietta, had stood idle. In response, authorities earmarked the fast-tracking of significant gas developments, including BP’s Atoll and West Nile Delta (WND) projects, alongside Eni’s Nooros Field.
Then the 30 Tcfg (in place) Zohr discovery came along in September 2015, at just the perfect time. Nooros was brought onstream in September 2015, WND saw first gas in March 2017, with Zohr coming online in December 2017. Atoll soon followed in February 2018, seeing the total addition of c.40 Tcfg of resource available for production. Concurrently LNG exports at Idku terminal have restarted, albeit modestly at c.500 MMcfg/d. A new gas marketing law was passed in 2017, liberalizing the gas distribution market. In 2018, Noble Energy signed a deal with Dolphinus Holdings to supply gas over a 10-year period (via the East Mediterranean Gas Co pipeline from Ashkelon to El Arish), and a proposed gas pipeline between Cyprus and Egypt was ratified by both countries. LNG imports also ceased in September 2018. The recent EGAS 2018 International Bid Round also saw 13 blocks for tender, the largest offering since 2001. Just three were ultimately pre-awarded, to ExxonMobil (one) and Shell/PETRONAS (two). All three blocks are in the prolific inboard and mature part of the Nile Delta.
No bids were successful in the deepwater frontier acreage where Zohr lies, which brings us to the potential thorn in the side of the gas hub debate. Yes, gas from Cyprus (via Aphrodite) may eventually come to Egyptian shores and possibly also Israeli gas (from Leviathan, Tamar and others). However, it is the indigenous gas supply that could potentially become an issue. Since 2016, there have just been five wildcats drilled in the offshore Nile Delta. Four of the five (Baltim South West 1, Nour 1, Swan East 1, Qattameya Shallow 1) were successful, but have added just around c.2 Tcfg to the resource figures. A maximum of 13 NFWs are planned offshore in 2019, although in reality only around half are likely to be drilled. Coupled with a two-year hiatus between Mediterranean licensing rounds (EGAS 2015 and EGAS 2018 bid rounds), and the delay to the launch of a tender offering for the frontier western portion of Egyptian’s Mediterranean waters, there remains a lot of undrilled acreage in the Nile Delta. In reality there is a need for a ramping up of exploration offshore Egypt in the short term, and ideally the finding of another multi-TCF discovery, in order to both sustain the gas-hungry nation, as well as continue to contribute to the gas hub picture into the future.
Figure 4. Egypt’s exploration and production licenses in the Eastern Mediterranean.*
The gas in the Eastern Mediterranean provides risks and opportunities alike for the littoral states. Further successful exploration campaigns and export solutions could significantly help reduce the energy dependence for some of the countries and provide additional revenue to the public coffers. However, even if further significant resources are discovered, it is not guaranteed these will be quickly developed. As shown in the case of Aphrodite and Leviathan, a number of factors can result in long delays.
In addition, complex geopolitics always present a challenge in the Eastern Mediterranean. Should resources be discovered in disputed waters, it could potentially cause further friction in the area, or worse. On the other hand, the common desire to profit from the gas riches in the region might lead to more collaboration. A case in point is the establishment of the East Med Gas Forum, which includes seven members – Egypt, Israel, Greece, Cyprus, Jordan, Italy, and the Palestinian Authority. However, the absence of Turkey and Lebanon highlights the difficult relationships
As mentioned above Egypt’s hopes of becoming a gas hub in its own right in the Eastern Mediterranean are dependent on the country’s indigenous demand and future exploration success. However, taking the significant discovered resources in Israel and Cyprus into account, the idea of Egypt becoming a gas hub is not implausible. Another much discussed possible export route for Israeli and Cypriot gas is the EastMed pipeline from Israel to Italy, via Cyprus and Greece. The current design envisages a 1,300km offshore pipeline and a 600km onshore pipeline, capable of transporting 353 Bcfg per year. The project has been deemed technically feasible and financially viable by IGI Poseidon (a 50-50 joint venture between Edison and DEPA). However, questions remain on whether the gas transported through the pipeline could compete with gas from other sources, like Russia and U.S. (LNG).
* The maps are not an authority on international boundaries.
firstname.lastname@example.org – Regional Manager Middle East
email@example.com – Regional Manager North Africa
East Med Gas Hub – future reality or pipe dream?
Natural gas storage inventories increased 92 Bcf for the week ending April 19, according to the EIA’s weekly report. This injection is slightly above the market expectation, which was an inventory increase of 90 Bcf.
Working gas storage inventories now sit at 1.339 Tcf, which is 55 Bcf above inventories at the same time last year and 369 Bcf below the five-year average.
At the time of this writing, the May 2019 contract was trading at $2.450/MMBtu, $0.012 below yesterday’s close of $2.462/MMBtu.
Last week, prices broke below the three-year support of $2.522/MMBtu. Prices have remained below this area and have bounced around this week between $2.45 and $2.52. The main factors keeping prices suppressed are the mild weather, causing lower demand, and the supply increase year over year. The lack of demand is giving the market the chance to inject volumes throughout April, unlike last year. On top of weak demand, the lower 48 are producing ~9 Bcf/d more gas than this time last year.
Prices this summer will be mostly driven by weather. A warmer-than-normal summer will create less opportunity to inject gas into storage, potentially leaving EOS inventories below the five-year average and giving a bullish sentiment to the market. However, an average to below-average summer, in terms of temperatures, will allow more gas to be injected and will likely keep prices down.
See the chart below for projections of the end-of-season storage inventories as of November 1, the end of the injection season.
This Week in Fundamentals
The summary below is based on Bloomberg’s flow data and DI analysis for the week ending April 25, 2019.
- Dry gas production decreased 0.15 Bcf/d on the week. A majority of the decrease came from the South Central from declines in Oklahoma (-0.13 Bcf/d).
- Canadian net imports decreased 0.30 Bcf/d on the week.
- Domestic natural gas demand decreased 4.11 Bcf/d week over week. Res/Com demand continues to decline with the change in season, having fallen 4.18 Bcf/d on the week. Power demand showed a gain of 0.44 Bcf/d, while Industrial demand fell 0.37 Bcf/d.
- LNG exports increased 0.21 Bcf/d week over week, while Mexican exports remained relatively flat.
Total supply is down 0.45 Bcf/d, while total demand decreased 4.05 Bcf/d week over week. With the drop in demand outpacing the drop in supply, expect the EIA to report a stronger injection next week. The ICE Financial Weekly Index report is currently expecting an injection of 119 Bcf, another April injection record if the injection comes to fruition. Last year, the same week saw an injection of 62 Bcf; the five-year average is an injection of 71 Bcf.
Natural gas storage inventories increased 92 Bcf for the week ending April 12, according to the EIA’s weekly report. This injection is slightly below the market expectation, which was an inventory increase of 95 Bcf.
Working gas storage inventories now sit at 1.247 Tcf, which is 57 Bcf below inventories at the same time last year and 414 Bcf below the five-year average.
At the time of this writing, the May 2019 contract was trading at $2.491/MMBtu, $0.026 below yesterday’s close of $2.517/MMBtu.
This week brought another larger-than-normal injection to the market, bringing inventories another step closer to the five-year average. Also this week the market broke below support at $2.522/MMBtu. This area has held support for nearly three years and had been tested multiple times before it was finally broken yesterday.
Weather has been moderate, causing low demand for power and heating. This moderate weather coupled with LNG maintenance over the past couple of weeks has caused early summer injections. Looking at the next couple of weeks, the weather remains moderate, and injections look to reach triple digits for the first time in April since 2010. The largest April injection recorded by the EIA was already broken this week and will possibly be broken again before the end of the month.
See the chart below for projections of the end-of-season storage inventories as of November 1, the end of the injection season.
This Week in Fundamentals
The summary below is based on Bloomberg’s flow data and DI analysis for the week ending April 18, 2019.
- Dry gas production increased 0.23 Bcf/d on the week. The slight gain was mainly due to increases in the South Central (+0.28 Bcf/d) region.
- Canadian net imports increased 0.26 Bcf/d on the week.
- Domestic natural gas demand decreased 1.13 Bcf/d week over week. Power demand was the leader in the drop, falling 1.43 Bcf/d. Res/Com showed a drop of 0.04 Bcf/d, while Industrial demand increased 0.28 Bcf/d on the week.
- LNG exports increased 1.50 Bcf/d week over week, as maintenance at Sabine Pass has been wrapped up. Mexican exports decreased 0.23 Bcf/d.
Total supply is up 0.49 Bcf/d, while total demand increased 0.14 Bcf/d week over week. With the gain in supply outpacing the gain in demand, expect the EIA to report a stronger injection next week. Last year, the same week saw a draw of 18 Bcf; the five-year average is an injection of 52 Bcf.