Following a quiet summer, E&P activity in the Eastern Mediterranean is gathering steam towards the end of 2018. Several significant exploration wells are planned in the near future, and acreage offerings are being prepared across the region.
To date, six exploration wells have been drilled offshore Cyprus, three of which have been successful. Noble Energy drilled one well in 2011 and one in 2013, discovering and confirming gas in the Aphrodite field (estimated at 4.5 Tcf recoverable). Eni targeted the same play in Block 9 in 2014 and 2015, 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 were impeded by Turkish military vessels, which prevented the drillship from reaching the wellsite.
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 UN 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 UN 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, whereas the Eni-operated Calypso 1 NFW on Block 6 was announced as a gas discovery. Calypso reportedly contains 6-8 Tcf (assumed to be GIIP); Eni plans an appraisal program. Further exploration drilling will be carried out by ExxonMobil, with the company planning to conduct a two-well back-to-back drilling campaign on Block 10 in late 2018 to early 2019.
While there had been talk of another offshore bid round, the Cypriot cabinet has decided to go a different route this time around. In early October 2018, it invited energy companies already licensed to explore offshore Cyprus to submit their expressions of interest (EOI) for Block 7 (Herodotus Basin). The invitation concerns 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 1 NFW is located in the south-east corner of Block 6, suggest that the Calypso structure extends into neighboring concessions.
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 have been drilled in the Eastern Mediterranean since 1966, with the last being drilled in 2014. None has been successful so far, 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 data in the Black Sea as well as the Mediterranean. In the Eastern Mediterranean, the vessel has concluded at least six separate surveys, with another currently ongoing. Surveys have been acquired to the northeast and southwest of Cyprus, parts of which cover disputed areas.
Turkish officials have stated on various occasions that the country will take steps this year toward exploring and drilling in the Mediterranean. To this end, TPAO acquired its own drillship, the “Deep Sea Metro II” (now renamed “Fatih”), in late 2017, and has recently signed a two-well contract with Rowan Companies for the “Rowan Norway” ultra-harsh environment jack-up rig.
While the Fatih drillship is expected to start drilling its first well, Alanya 1, in the Gulf of Antalya in late October or early November 2018, the planned drilling locations for “Rowan Norway” have not been revealed. However, the N-class jack-up has a rating of 120m, so it is likely to be targeting prospects in the aforementioned Gulf of Mersin. Some reports suggest that in future, TPAO will conduct drilling operations in contested waters around Cyprus. For the ultra-deep water “Fatih” drillship with a rating of 3050m, the water depths in the Eastern Mediterranean present no problem, allowing it 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 JV 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.
Prior to the drilling of the first offshore well, Lebanon will open its Second Offshore Licensing Round. The Lebanese Petroleum Administration (LPA) announced preliminary details of the bid round in late July 2018, proposing a launch in late 2018. An unspecified number of blocks will be made available in a competitive and open tendering process, which is expected to conclude towards the end of 2019. At present, out of the ten demarcated offshore blocks, eight are unlicensed.
A four-month period, from January 2019 to the end of April 2019, has been reserved for companies to submit their applications for prequalification. Following this, 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 over a period of at least six months, from May 2019 to October 2019. Once bids are submitted, the LPA will evaluate them and prepare a recommendation to the Minister of Energy and Water and the cabinet by November 2019.
Figure 2. Lebanon’s exploration blocks. All or parts of the open acreage may become available in the Second Offshore Licensing Round. *
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 around 64 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 to be 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 is expected to start in Q1 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 with firm plans to conduct exploration drilling in the near future. It is planning to spud the Karish North near-field exploration well in March 2019, and has the option to drill a further exploration well on completion of the Karish development drilling campaign.
There may also be another offshore bid round. Israeli officials have announced on several occasions that a Second Offshore Licensing round was under consideration, with launch dates between late 2018 and early 2019. Following disappointing results in the first bid round, contractual modifications may be made to make the bid round more attractive. However, no details have been revealed yet.
Figure 3. Israel’s exploration and production licenses. The First Offshore bid round grid may be utilized for a Second bid round. *
The upcoming exploration activity in the Eastern Mediterranean provides risks and opportunities alike for the littoral states. Successful exploration campaigns could significantly help reduce the energy dependence for some of the countries and provide additional revenue to the public coffers. However, even if significant resources are discovered, it is not guaranteed these will be quickly developed. As shown in the cases of Aphrodite and Leviathan, border disputes and regulatory changes can result in long delays. In addition, should resources be discovered in disputed waters, it could potentially cause further geopolitical friction in the area, or worse.
* The maps are not an authority on international boundaries.
I-10 stretches a staggering 877 miles across Texas, encountering countless different cities, speed limits, potholes, and restaurants along the way. In the GLO’s recent offering of over 115k net acres across 335 tracts across the state, the vast expanse of Texas’ mineral wealth comes into focus. The acreage is scattered across 20 different counties meaning companies of every scale will be looking at it.
- Permian Basin headlines the marketing sheet for this offering
- With acreage scattered through Reeves, Culbertson, and Pecos this deal has a decided Delaware lean. The Reeves and Pecos Acreage is bracketed by Chevron and Centennial’s acreage serving to ignite higher bidding with the recent acreage swaps and sales in the area by the two drawing more eyes. Centennial’s latest 8,600 net acre sale came out to $16,400 per acre, closing this month, shows interest in the area.
- South Culberson tracts draw the most intrigue (read: speculative) with a 2014 State sale to John Wollcott hugging the Apache acreage on the border of Culberson and Reeves. Apache currently has 2 rigs running just over the border with 7.5 miles of the closest offered GLO tract. While there has been a well that came on very modestly to the south of the offered acreage, it was brought on 10 years ago and currently there is no recent production around the tracts. Apache continues to permit clusters of 16000 ft permitted wells on the SE to NW trend, extending just over the county line. They have dubbed this area their ‘Northern Flank’ and with well costs between $4-$6 million and EURs in the 2bcf+ range, their economics look great. These new wells are boasting a 2 year breakeven period and higher oil cuts come into play in the northern tracts.
In figure (Orange tracts are the offered land): Landtracs that have not expired are colored by expiration date. Note there are many expiring tracts coming up in the next 3 months. All rigs permits and production shown in Reeves county is tied to Apache.
Gas EUR Curve for recent Apache Well and Economics DCF
- Haynesville/Cotton Valley
- Tracts in Harrison and Rusk offset better recent production, but lack size at 37 and 4 acres respectively.
- Marion county seems to be the jewel of this offering with Herd Production having a rig on location, drilling a wildcat, just to the North East of the 514 acre tract. Here the Cotton Valley has been de-risked in the southern offsets and this acreage sits in a nice 500-1,200 ft updip of the more core areas. The wildcat could offer upside drilling a shallower horizontal well permitted to 7000 ft.
- Galveston Bay
- Torrent and Linc serve as the two recent operators to drill in Galveston Bay, west of the offered blocks. Their efforts have largely targeted Frio and Miocene reservoirs to a standard measured depth around 7000 ft. Average EURs, for bay wells first produced in the last 5 years, are around 118k bbls and 63k mcf. The type curve indicates 3-4 years to breakeven and comes with the conventional disclaimer that well performance varies greatly.
- Onshore, Hilcorp drilled the closest economic well, 12k+ ft down to the Vicksburg. Currently about 3 years into production, the EUR looks to be around 2 bcf with steady oil figures staying between 10k and 18k bbls a month during that time period. These figures hammer home a sub 12 month breakeven and spectacular returns. Again, this well is over 5 miles away from the nearest offered tract.
As more public lands come up for lease, the GLO is the latest to offer up acreage scattered across Texas with a good mix of conventional and unconventional acreage. Currently marketed on EnergyNet, prominent shale counties are listed as the main draw for this offering but there are other offerings that are high traffic areas. With New Mexico’s latest 2100 acre offering taking place last month, Texas is looking to improve on the $1,000 per acre mark of their neighbor to the West … smart money is that they will!
All activity and charted values filtered to a 5 mile buffer zone drawn around offered acreage (red polygons). Culberson leads the way with highest peak rates in the buffer zones, but Reeves leads in leasing and permitting activity. Offered tracts are outlined by blue ovals denoting a 5 mile buffer.. The Heat map above shows statewide leasing activity in the last 90 days where darker red is more activity and green is less.
First production occurred in Last 5 Years, bubbled by the highest month of production in a barrels of oil equivalent. Offered tracts outlined in Red.
First production occurred in Last 5 Years, bubbled by the highest month of production in a barrels of oil equivalent. Offered tracts outlined in Red.
Strong Wolfcamp A and B production along the Reeves/Loving border shows stacked potential. DI Landing zones are driven by a DI geologist-picked earth model and using directional survey data to diagram which bench the majority of that lateral fell in. Offered tract outlined in Red.
Two offset rigs running and strong Wolfcamp A production is complimented by one disappointing Wolfcamp C well and one moderate Wolfcamp C producer. Colored by DI Landing Zone, bubbled by the highest month of production in a barrels of oil equivalent. Offered tracts outlined in Red.
Reeves County, south of Pecos. Bubbled by the highest month of production in a barrels of oil equivalent. Offered tract outlined in Red.
Larger Red well is a 2008 vertical gas well that has been recompleted twice, permitted deep 12k ft. State reported as a ‘Shale’ target. All other smaller circles are historic, inactive wells.
Wells colored by state reported reservoir and sized by highest month of production in a barrels of oil equivalent.
Galveston Bay offering in Red Outline, Circles with white centers denote recent leasing and are colored by Grantee. Production in bay is largely Miocene or Frio; production bubbled for wells that first produced in the last 12 months. Linc and Torrent are the bubbles closest to La Porte and represent the only offshore wells brought on in last 5 years.
Heat map shows Lease activity in the last 90 days where darker red is more activity and green is less.
Modern shale drilling has largely to date been a 2-dimensional activity. The operator drills horizontally through a single shale layer with wells then taps one layer at a time.
That is, until now!
Spurred on by the potential benefits of economies of scale and improved well productivity rates, operators, such as Encana and Devon Energy corporations, are starting to drill multiple shale layers simultaneously.
And the numbers are staggering! On the Permian Davidson well pad, Encana has 19 well operations collectively pumping almost 20,000 barrels of crude, according to company reports. Encana also has a 28-well operation in the Montney shale play in Alberta and British Columbia, and Devon has a 24-well enterprise in Oklahoma.
So, what does this mean for the industry?
In Alex Nussbaum’s recent Bloomberg Businessweek article “Permian’s Mammoth Cubes Herald Supersized Future for Shale,” Sarp Ozkan, Head Analyst at Houston-based Drillinginfo, the energy industry’s leading data analytics company, commented on the potential impact of this new large-scale manufacturing technique as opposed to the one-well, one-layer-at-a-time approach of the past.
“A move toward cube development could spur more consolidation as companies without the financial or administrative might to pull off industrial-size operations get snapped up or pushed out,” Ozkan said, pointing to the expense of Encana’s Davidson well pad operations with JPMorgan Chase & Co. predicting costs of up to $120 million.
This would include extra well costs, added pumping power, larger tank batteries and significant numbers of additional personnel required, according to the Bloomberg article.
There are also implications for the delicate global supply and demand market with “production potential only as high as the demand will allow it to go” according to Ozkan.
He continues: “Cube development could have a big influence on oil and gas markets: If the industry takes a more cautious approach, U.S. output could fall below forecasts in the coming years, easing some of the downward pressure on prices. If Permian producers master new manufacturing modes, on the other hand, the global supply glut may only get worse. You add all the numbers up and what you start to come up with is very, very scary.”
Yet, not all operators are sold on cube development. Permian operators, such as Pioneer Natural Resources and EOG Resources Inc, for example, are taking a more conservative approach to well pad expansion because of concerns over costs and well performance when operating so many simultaneously.
According to a spokesperson from EOG, which has limited itself to six to eight well pads so far, “the impact to returns is not clear-cut until you understand the impact to well productivity and other operations costs.”
It would seem that in terms of increased well performance from cube development, the jury is still out. Sarp Ozkan again: “It’s too early to say which side, if either, is right, although that may change this year as more results become available from large-scale production. For now, there’s no sign cube wells are any less productive though.”
What is clear though, is that major changes in production and manufacturing techniques are taking place in the shale market, with Drillinginfo tracking such developments every step of the way.
For more information on Drillinginfo’s leading data analytics products, delivering critical business insight and maximizing investment returns, visit https://info.drillinginfo.com.
The GOM Lease Sale 250 results were reported this morning. As a whole there were 159 bids on 148 tracts, with a total of $124.7MM(US) high bids and $139.1MM(US) total bids. There were 33 companies that participated with 24 walking away with new acreage (Figure 1). More detailed information from the DrillingInfo scouts about each block bid & all awards at the bottom of the article.
Most companies won everything they went after as there was only 7 contested blocks. All had 2 bids with the exception of MC 509 with three bids. The block was awarded to LLOG; the only block they bid solo. There were 10 blocks with joint bids, with LLOG leading the partner game forming alliances with 5 companies for the 250 Lease Sale. Total had the highest bid on MC 697, beating Chevron with their just over $7MM(US) offering. Closest bid was on MC 513, where Hess squeaked it out for an additional $3,001(US)over LLOG and partners Ridgewood & RedWood. The second closest block was fought over by 2 supermajors, MC 787, with $26,744(US) granting Chevron victory over Exxon.
BP came out strong, awarded the most blocks in the sale (27); showing their interest in continuing operations in the GOM. Surprisingly, Anadarko didn’t participate in the sale, while their big competitors BP, Chevron & Shell were highly active. BP and Shell won on all blocks they sought after (27 & 16) while Chevron won 24 and lost 5.
EnVen & W&T offshore showed some strategy change to their current portfolios; participating in the sale yielded 6 & 8 blocks respectively.
Stay tuned for more from DrillingInfo from the GOM area as we will published a GOM Article Series over the next few months covering the happenings in the GOM including results from the upcoming May Mexico lease sale and August 251 lease sale.
Figure 1: GOM Lease Sale 250 block awards by operator.
Figure 2: Pre-250 block count by operator with the 250 GOM Lease Sale block awards added to the top 25 operators by block count prior to the 250 Lease Sale. *Fieldwood Energy count includes Noble blocks sold to be awarded after restructuring.
Interested in learning more?
Please contact the DrillingInfo GOM Team:
Donald Campbell, Senior Analyst – Frontier North America Donald.Campbell@drillinginfo.com
Tom Liskey, Regional Mgr – Americas Tom.Liskey@drillinginfo.com
Robyn Marchand, Technical Advisor – DrillingInfo Robyn.Marchand@drillinginfo.com
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As Wall Street discounts stacked pay by punishing high cost per acre, Eclipse Resources made an interesting play in January to lower their average per-acre costs that stirred investors. After announcing their acquisition of Travis Peak’s 44,500-net-acre, $93.7 million Flat Castle project in Northeast Pennsylvania, their stock dipped initially before jumping 20%. This $1,900-per-acre cost is less than the recent deals targeting the Utica in the Appalachian Basin. After their Jan. 30 analyst day, their stock took another prolonged dip. With the recent big swings in Eclipse’s market cap, looking into this latest acquisition finds there is more than meets the eye!
Deal Summary and Conclusions
- Overall, there is a lot to like with this deal. Management was able to stay within the Appalachian Basin, which it knows well, and can implement their 16,000-foot laterals and aggressive proppant volumes. Although payback periods leave something to be desired, payback appears achievable if cashflows are managed correctly.
- A $1,900 average cost per acre comes in much less than recent deals for core Utica acreage.
- All equity-based purchase is a huge benefit, reducing cashflow risks associated with a cash-based purchase.
- A projected to the 32 bcf wells stated on the investor relations reports.
- In both the base case and upside case, extended payback periods were observed (around 9.1 and 7.7 years respectively), providing potential negative sentiment from shareholders regarding this acquisition.
- The combination of an option to purchase Cardinal NE Holdings from Cardinal Midstream II for $18.3 million and the purchase being far west of northeastern Pennsylvania Marcellus production reduces midstream risk for the project. However, New York is directly to the north and has not allowed new pipelines to be built for some time, raising takeaway capacity concerns. Takeaway capacity will be a focus throughout this project’s life cycle.
- The investor relations report states 87 drillable locations with a “wine rack” potential. The 87 locations seem reasonable assuming 1,200-foot spacing. With this stated, drilling all potential locations with their current rig program is questionable, especially if the wine rack style drilling is going to be implemented. This requires larger interval thicknesses.
- Drilling longer laterals can lead to a reduced per-foot cost associated with drilling. However, higher upfront D&C costs lead to a longer breakeven times.
- There is only one well producing from the Utica on this acreage (the Travis Peak drilled well), which creates a major concern with de-risking the expected EUR for new wells.
- Economic incentives for drilling in this area include a low royalty burden of 17.7% on average and no current severance tax.
- Statements by Eclipse that increased proppant volumes and lateral length will correlate with higher EURs appear to be warranted.
Map containing Point Pleasant Formation structure, active wells in the area colored by operator, leases colored by grantee, and the acquired acreage area.
Investor Relations Report Completions and Drilling Analysis
- Peak gas appears to positively correlate with horizontal length and total proppant in the area of interest.
- Due to limited drilling in the Utica in this area, the entire Utica Shale play was analyzed. Lateral length and proppant totals appear to have a positive impact on peak gas.
Horizontal length vs peak gas in the Flat Castle project area and neighboring wells. Wells are colored by operator.
Perforated interval length vs peak gas in the Utica/Point Pleasant. Wells are colored by first production date.
Total proppant vs peak gas in the Flat Castle project area. Wells are colored by operator.
Total proppant vs max initial production BOE in the Utica. Wells are colored by operator.
Deal Analysis and Inputs
Inputs and assumptions for PDP and PUD calculations
The rig schedule was calculated using DrillingInfo’s Rig Analytics tool. The days on-site for Eclipse wells with extreme lateral lengths (classified as over 15,500 feet) were filtered and days on-site were averaged out. To stay conservative, lower time-on-site extremes were filtered out. The average rig on-site time was determined to be 26 days. This value was then applied to a two-year drilling program, giving the program 28 wells total.
The drilling program was limited in this study to two years for several reasons. One is that new opportunities can occur in a basin rather quickly. It is difficult to project past two years into the future as drilling plans and company focuses change over time. In addition to this, we calculated drilling to begin in Q1 of 2019. This means we are forecasting three years in total. Forecasting beyond this seemed aggressive. If desired, further drilling can be forecasted using similar methods. Both scenarios assume one rig is mobilized to site.
Base Case Results
- Uses wells in an expanded area of interest.
- 25.8 bcf EUR is below IR reported 32 bcf, but is still solid.
- 9.1 year payback period at 10% discount rate. The long time frame is due to the high D&C costs.
- IRR of 26% and a PV10 of around $6,300,000.
- 28 well drilling program.
Upside Case Results
- Uses only the Travis Peak well on the acquired acreage.
- 26 bcf EUR is below IR reported 32 bcf, but is still a strong projection.
- 7.7 year payback period at 10% discount rate.
- IRR of 30% and a PV10 of around $7 million.
- 28 well drilling program.
- Items to weigh: Long laterals account for an increase in peak rates, but proprietary cost per proppant and lateral drill costs are needed to assess fully return profiles.
- Takeaway capacity to the north is an area of concern. New York lawmakers are making it increasingly difficult to pass any legislation allowing further pipeline construction. If the area is indeed proven up by future wells, more operators could move in and produce, which would further complicate takeaway capacity.
- Sensitivity analysis regarding price was ran at $2.50 per mcf. At this rate, the project breakeven at a 10% discount wasn’t until year 10.
Thoughts of Peru typically conjure up a land of mystery. From its most popular tourist destination of Machu Picchu high in the Andes Mountains, where visitors flock to witness the grandeur and beauty of the Incan culture and the magnificent ancient city constructed without the benefit of modern tools or technology, to the elaborate Nazca Lines in the deserts of the south, depicting huge figures that can only be seen from the air, people around the world see the country as an exotic and mysterious place. One would not expect this enigmatic quality to carry over to the country’s hydrocarbon industry but in many ways, it does.
Licensed acreage by operator
Since 2003, when the country overhauled its hydrocarbon law to attract investment, industry analysts have touted the country as an under-explored prospective area, and with some success. Peru held record-setting bid rounds in 2005, 2006 and 2007, licensing a large percentage of the country. However, many of those blocks have spent long periods suspended in force majeure, have seen little or no exploration and are now being relinquished. After the licensing boom of 2005-2007, five new exploration and production license contracts were awarded in 2011, and then none were awarded until 2017 when Anadarko signed three new offshore exploration and production license contracts in the Trujillo Basin as a newcomer to Peru. Later in early January 2018, it was announced that another newcomer to Peru, Tullow Oil, had agreed to terms and would soon be awarded five more exploration and production license contracts in the offshore.
It seems now the rush is on in Peru for offshore acreage, even though no one has ever drilled a commercial well in Peru in deeper than 200 meters of water. Meanwhile, 15 technical evaluation contracts were active at year’s end, with 13 of them awarded in 2017. On the other hand, 20 contracts were suspended due to active force majeure, with 10 relinquished exploration contracts and 18 active exploration licenses at year’s end 2017. So, what do we make of this muddled and contradictory picture? Are operators fleeing from Peru or flocking to it, and what is the rationale on both sides?
First consider those coming to Peru: Tullow and Anadarko. These license contracts for the offshore are obviously very exciting and enticing, offering large tracts of prospective frontier, virgin acreage in an attractive fiscal framework with reasonable terms and commitments. Why isn’t everyone chasing that acreage? In fact, Peru does not even have provisions in their hydrocarbon law for deepwater oil and gas operations. Legislation was submitted to Congress by center-right President Pedro Pablo Kuczynski in November to remedy this. This legislation also includes many other measures designed to make the sector more attractive. However, Congress is dominated by the opposition party Fuerza Popular, led by Keiko Fujimori, which has yet to address the legislation and may not consider it a priority.
It seems these operators are now looking at offshore Peru as a way to explore in the country while minimizing some of the issues with the prior consent law and the very difficult task of attempting to monetize discoveries in prospective basins in the jungles east of the Andes.
Regarding the 13 technical evaluation agreement (TEA) contracts awarded in 2017, operators seem to have found a good way to explore in Peru with minimal investment commitment. These two-year contracts carry no production or drilling rights and provide a way for operators to study the block with preferential rights to negotiate a license contract at the end of the TEA, if they like what they see. Eight of the TEAs were approved for Global Petroleum for blocks XLV, XLVI, XLVII, XLVIII, XLIX, L, LI and LII with a total area of 34,137 sq. km.
Most of these frontier blocks are concentrated in the south-central Andes and Titicaca Basin while one is in the Moquegua Basin. Repsol, a longtime Peru operator, was awarded the other five TEA contracts for 2017 in the frontier Pisco Basin of southern Peru. Repsol had been approved for eight TEA contract awards but has delayed the signing of three of them in the highly productive Ucayali Basin in proximity to the country’s world-class Camisea gas fields. Repsol may still sign for these blocks and get the awards, but Peru’s hydrocarbon regulator, Perupetro, has imposed a fast-approaching deadline to do this, and the company could miss out on what appear to be the most valuable TEA blocks in Peru’s most productive basin and area for unknown reasons.
TEA contracts awarded in 2017
After this abbreviated summary of the pro-Peru case for exploration and production in the country, it is also useful to look at the companies leaving the country and examine the whys in this scenario.
As stated earlier, Peru had great success with record-setting rounds in 2005, 2006 and 2007. However, these victories may have been less than they appeared to be at the time. Company qualification standards to bid in the round were quite low, enabling many small and undercapitalized companies to win blocks. These companies tended to underestimate the cost of their commitments in these Maranon and Ucayali basin blocks in the jungles east of the Andes.
For example, the comprehensive environmental impact statements (EIS) required before exploration activity can even begin on a block. These often require extensive benchmarking of parameters in both the rainy and dry seasons. They frequently take a minimum of 18 months to complete and may take another year to be approved by the government. This means a delay of 30 months and a few million dollars just to get started.
The regulator (and promoter of the round) added to these underestimations by the operators with unrealistically low cost estimates for some of the drilling commitments. For example, road infrastructure in Peru east of the Andes is virtually non-existent and the building of access roads to drill a well in those areas is usually prohibited. The process for most explorers in that region was to select the most favorable location and drill a well using a combination of river and helicopter transport to move the rig and supplies for drilling the well to the site, at a predicted cost of 100 million. However, this well-cost estimate was based on 10 years earlier when an operator in that region used a drill barge to target a prospect in or on the riverbank at maybe one-tenth of that cost.
This does not even address the cost of monetizing a discovery east of the Andes. This has not been done since the world-class Camisea gas fields in 1984, which took 20 years and was only completed after Shell abandoned the project after 14 years of getting nowhere. Two more recent examples of viable discoveries that have been abandoned were Gran Tierra on Block 95 in the Maranon Basin.
In early 2015, a potential 100 million bbl field was scaled back to 57 million and development plans halted after an appraisal encountered a productive zone much thinner than expected. In 2012 Pacific Rubiales, now Frontera, discovered oil in Ucayali Basin Block 126 with the Sheshea 1X. The Chonta Formation flowed 1,430 bo/d with no water cut and a reserve estimate of 14 to 140 MMbo (if structure filled to the spill point) for the discovery. However, the operator ultimately walked away without even drilling an appraisal well for the discovery. This was probably due mostly to the financial hardships of the operator, but it means there is a potential 140 MMbo of already-discovered oil out there waiting to be developed and marketed, and this may not be enough for a commercial onshore discovery.
In summary, the Peruvian government for the last 15 years has said and tried to do the right thing for the country’s hydrocarbon sector but for various and complex reasons has not always been able to deliver the desired results. The country remains vastly underexplored in its most prospective regions compared to, say, the United States.
However, some companies have recently identified opportunities in the offshore where giant discoveries are possible and which are likely to be much less impacted by the Prior Consultation Law and its resulting NGO leverage. This all leads back to the original question posed at the beginning of the article, “Is the glass in Peru half full or half empty?” Time may provide a clearer answer, but at this stage it is in the eye of the beholder.