In my previous post, I described our ongoing work to build the Oil & Gas industry’s first M&A deal evaluation platform that will incorporate the databases and technologies of the three most trusted sources for information and analysis: Drillinginfo, PLS and 1Derrick. We’re building a “single pane of glass” that will revolutionize how you research and evaluate potential and completed deals, no matter what area of our industry you represent.
Drillinginfo has built its reputation as the industry-leading provider of data and analysis for decision-making in the oil & gas space. Our acquisitions of PLS and 1Derrick enable us to deliver a new depth of insight, specific to the transactions that happen in the industry and delivered to a much broader audience, including C-level executives, M&A professionals and others who want more context around transactions. We’ll be able to deliver the most relevant information related to deals in a matter of minutes on all their preferred devices.
What Once Took Days…
Let’s use a recent real-world example to show how our new platform will put actionable intelligence right at your fingertips at any time, wherever you are.
- Diamondback Energy announces it will acquire Energen in an all-stock transaction for $9.2 billion:
- You receive a push notification with the news on your phone via the Drillinginfo mobile app because you have set up a Drillinginfo “Virtual Scout” that constantly monitors for news related to parameters you pre-defined including buyers, sellers and custom areas of focus.
- You’ll receive notifications whenever buyers and sellers you specify complete a transaction or post a deal for sale offset from your core acreage positions.
- You open the app and tap on the deal to view the deal terms, the deal report and other related information, analysis and commentary compiled from the unmatched combination of the Drillinginfo, PLS and 1Derrick analysts and platforms. This includes comps and other information about publicly reported IP’s, type curves, etc., complete with links back to source documents.
- Within seconds, you can map the deal within the app to see acreage position and add layers of active rigs, permits and deals for sale to instantly get more context into the transaction.
A Team Effort
Go back to the Activity Detail screen and tap on the “Alert Team” button to save the deal to a workspace in your Drillinginfo dashboard and send an alert to your team. Your lead analysts jump into research mode by quickly accessing that same workspace in the Drillinginfo web or mobile app, which by now has the acreage position and other relevant context such as offset production and transactions, permits, rigs, leases and type curves.
If you’re familiar with our web app, you’ll notice one very important new addition: M&A Data Sets. This is where you can filter all the transactions you’re following by a number of factors including location, date, deal types and value and acreage.
Let’s say one of your analysts wants to see the impact the Diamondback-Energen deal will have in Reeves (Tex.) county. Setting that parameter returns a detailed map of all transactions in the county which you can color-code deals by values, price per acreage or a wide range of other factors to see how that deal stacks up.
Clicking on the Diamondback-Energen headline brings up the Transactions Card so the analyst can see all the details of the deal including direct links to relevant source documents.
Within an hour after your received that first mobile alert, you and your team have volumes of information at your disposal that would have normally taken days, even weeks, to compile.
We’re on schedule to launch our new dealmaker platform early next year. But we’re not going to wait until the calendar flips to 2019 to start rolling out some of the platform’s innovative features and capabilities.
Next month, we will launch a new product for O&G industry executives, investors, analysts and anyone else who wants to be able to quickly and easily evaluate deals that will demonstrate the power of combining data from the Drillinginfo, PLS and 1Derrick databases.
That’s all I can divulge for now, so stay tuned to this blog and be on the lookout for my next post… You can also stay up-to-date by following us on Twitter and Facebook.
Get ready to get smarter – faster – on what’s happening in O&G M&A.
An “Equation” to Be Solved
Hardly any topic receives as much attention from the oil and gas community as the Permian crude takeaway “bottleneck” problem. A careful reader may have spotted occasional discussions of capacity issues on the Permian-to-GoM route as early as the fall of 2017. It was about that time that the market became convinced that in 2018 oil prices would keep rising as OPEC continued to restrict its production and global demand, especially in Asia, remained robust. These factors converged to create an opportunity for more U.S. crude oil exports.
In the past weeks, however, the issue caught fire. The theoretically possible quickly turned into plausible, and then soon into mathematically probable.
The math here is transparent enough. Permian oil production, according to EIA data, hit 3.2 million bbl/d in early May. Current projections call for output to continue to rise to 3.6 million bbl/d by the end of 2018, and to reach as high as 5.3 million bbl/d in 2020. On the takeaway side, current pipeline capacity available for Permian producers to transport oil out of the basin equaled 2.8 million bbl/d in 1Q 2018. Several major projects are planned and being put in service (see chart below). If all of these are successfully funded and accomplished, total transportation capacity should rise to as high as 5.8 million bbl/d by the end of 2020. That will balance the supply/takeaway equation.
On the takeaway side, current pipeline capacity available for Permian producers to transport oil out of the basin equaled 2.8 million bbl/d in 1Q 2018. Several major projects are planned and being put in service (see chart below). If all of these are successfully funded and accomplished, total transportation capacity should rise to as high as 5.8 million bbl/d by the end of 2020. That will balance the supply/takeaway equation.
However, experts are warning that the actual “clogging” may occur in the interim. The EIA had estimated that as of December 2017, available space was only about 160,000 bbl/d on the region’s pipeline system, or about 4 percent of Texas’ output. Capacity may be insufficient by mid-year 2018, with a deficit possibly reaching as much as 290,000 bbl/d during the first half of 2019. In April 2017, Genscape estimated pipeline utilization from the Permian to the Gulf Coast at an average of 89 percent, climbing to 96 percent in a year’s time. At this level, some smaller producers may begin to suffer. Walk-up shippers that do not have their rising output fully committed to a particular pipeline may find no access, or only very high-priced access. By the end of 2017, Enterprise Products Partners (with its Midland-Sealy pipeline placed into timely service) was able to set a 62 percent higher tariff for non-committed volumes than the next best available option.
The takeaway problem is also manifested in the growing price differential ‘Midland to Cushing WTI’ from a $0.93 premium in January to a $3-4 discount in May. The price spread between Permian oil and Gulf Coast oil has been exceeding $15 /bbl in recent days, and is possibly soon headed for $20/bbl. The extra supplies of Permian crude are almost exclusively sold on the export market, so producers are driven to discount their output to accommodate higher transportation rates.
Other evidence of the issue is the 30 percent fall in prices for Permian natural gas. As more crude is produced, more associated natural gas is also produced. Existing natural gas pipelines are overwhelmed with supply and are not able to transport these growing volumes of gas out of the basin. Since flaring is restricted, if there is no gas takeaway producers have to cut back on their crude production. Texas state authorities recently said they were considering lobbying to expand flaring options (to greater than the typical limit of 180 days) to support producers.
Naturally, the bottlenecks are temporary and will eventually be resolved. In the meantime, producers are switching to alternate modes of transport such as rail or trucks. Some companies have reported still using pipelines but accepting new routing (usually less effective, but available).
Midstream operators are executing on short-term actions to increase their immediate takeaway capacity, at the same time they proceed with their long-term expansion plans.
Among the largest projects soon in service (see chart), Midland-to-Sealy and BridgeTex are expansion projects that are adding capacity to existing pipelines. The number of new projects approaches 20 pipelines/extensions that are planned to be ready by 2020. Not all of these will be built; experts point out that margins on many of the projects are expected to be very low due to high competition for existing customers.
By using Rextag’s pipeline mapping database, you can easy visualize the scale of the proposed infrastructure.
||Planned Capacity as of Mid-May 2018, Bbl/d
|EPIC Midstream Holdings
||EPIC Crude Oil Pipeline
||Near the New Mexico border to Corpus Christi
||End of 2019
||Midland-to-Sealy crude oil pipeline
||Midland-to-Sealy (Houston Ship Channel)
||Came into service in the end of 2017 with 300,000 bbl/d capacity. Keeps on expanding since then. Now adding new capacity again. Will eventually total 575,000 bbl/d
|Magellan Midstream Partners, Plains All American Pipeline
||BridgeTex oil pipeline
||West Texas to the Houston area
||Expansion project from 300,000 initially in the middle of 2017 to 400,000
|Plains All American Pipeline
||Permian to Corpus Christi
||Fall of 2019
||Gray Oak Pipeline
||Can be expanded to 1 MMbbl/d
||Seminole / Chaparral
||One of the two will be converted from NG into crude oil pipeline
||143-mile pipeline system
||Permian’s Delaware Basin to Midland’s Enterprise Terminal
|Other Than Crude Oil Pipelines
||Shin Oak Pipeline
||Permian to the Houston area
||Pecos Trail Pipeline
||West Texas to Corpus Christi
||Permico’s Texas NGL Project
||Permian to Corpus Christi
||To transport NGLs to service its planned 300,000 barrels per day-fractionator
Some operators make adjustments to increase the throughput of crude in their existing systems. Using DRA (drag-reducing agents) for this purpose is one solution. This does not require long-term and costly changes but rather looks like an ongoing improvement. Enterprise Products is trying another approach by converting one of two (Seminole or Chaparral) natural gas pipelines into a crude oil line.
Midstream operators also turn to local producers to tackle the problems. A ”quick-fix” solution is to build additional local gathering pipelines that help producers better access local markets. This can often be done “within the approved budget” and in reasonable time.
Industry analysts often turn to data providers such as Rextag to better understand a region’s growth history and its infrastructure bottlenecks.
As an illustration, you can see in the animation below how the industry has responded over the past 10 years for the Eagle Ford build-out.
Are any lessons already available for us?
Yes, there are some. Two conclusions seem obvious:
- While global forecasting again misses the desired level of precision (and may do that again and again), what counts as a big plus is the industry’s flexibility. This is the flexibility of producers that can use all modes of transportation and that are ready to take risks on price differentials. This is also the flexibility of midstream players that are ready to get the maximum out of a situation by boosting capacity and building those extra local gathering paths for smaller producers.
- You are always better off having a data-based plan than having no plan at all. Our highly competitive industry often finds itself fragmented when a cohesive and harmonious response to crises is most needed. Yet, there is a way to unite us all: it is using and letting others make use of accurate and integrated industrial data.
So, united with expertise and good-quality data we stand!
As oil prices reach a four-year high with Brent Crude at $78 a barrel and West Texas Intermediate (WTI) at $70 a barrel at the time of writing, it’s clear that we are entering a new phase in the oil and gas industry.
Furthermore, the fact that OPEC’s supply cuts have remained in place, the free fall in Venezuelan production, and the new sanctions to be reinstated against Iran – alongside strong global consumption forecasts – mean that the holy grail of $100 a barrel is no longer out of reach.
What does this new oil price boom mean for the North American shale industry and what trends should we look out for during the coming months?
A Regional Shake-Up
One result of the increasing oil prices is a regional shake-up of activity hot spots.
Over the last few years, the Permian has been the spearhead for drilling and production activity with the key attraction being its’ position as one of the least expensive places in the U.S. to produce – due to existing infrastructure and oil-bearing rocks that allow better yields per acre – as a recent Wall Street Journal article points out.
Yet, the rise in oil prices is bringing increased attention to other players in regions, such as Colorado, North Dakota and Oklahoma, where there are better pipeline infrastructures and lower costs per acre due to less competition.
According to Baker Hughes, in the same Wall Street Journal article, the number of oil rigs in several basins outside the Permian, including North Dakota’s Bakken region, the Eagle Ford in South Texas and the Cana Woodford in Oklahoma, has more than doubled over the last few years. This has led to operators, such as Continental Resources who favored the Bakken and Oklahoma over the Permian, posting production increases of as much as 48 percent in the first quarter.
With this regional shake-up and transfer of resources and drilling capital, it’s more important than ever for operators with multiple basins to have immediate and accurate access to regional data intelligence on leases; drilling, completion and production metrics; competitor information and other variables, as Drillinginfo provides.
In regard to specific regions, Drillinginfo also provides Oklahoma Spacing and Density – the only proprietary, fully-interpreted dataset of all current and historical spacing units in Oklahoma that allows operators to find open acreage faster, monitor competitor activity and identify hidden opportunities.
Increased Production and Self-Financing
Another impact of rising oil prices is a continued increase in production and more U.S. shale companies are now raising enough cash to cover the costs of drilling new wells.
The last few years have seen a significant drop in breakeven prices for shale producers – as much as a 45 percent reduction on the Permian according to industry analysts, Rystad Energy – leading to significant cash returns as operators look to increase production and rigs. The Drillinginfo daily rig count sat at 1105 as of May 13. That’s up 25 from two weeks previous and likely to keep in rising.
Several operators, such as Anadarko Petroleum, Devon Energy and Hess, have recently announced increased dividends or share buybacks and Continental Resources is prioritizing debt repayments – closing in on its goal of net debt below $6 billion.
This is all part of a new returns-based environment, where the key metrics and good business practices of cost containment, cash generation and returns on capital are over riding the ‘growth at all costs’ and need for continued outside investment approach.
A Focus on Efficiencies and Profitable Growth
Can this returns-based approach be sustained as oil prices remain on an upward trajectory?
The signs are good. At Drillinginfo, we are working with E&P operators who are dedicated to maximizing efficiencies and ROI in their operations. This includes identifying the most profitable leases, monitoring the competition, ensuring optimal well spacing and conducting in-depth analyses of best drilling and completion practices.
While shale production remains on the increase, the Energy Information Administration (EIA) predicts that shale oil production will rise by a record-breaking 144,000 barrels per day from May to June this year, but rig counts are not increasing in the same numbers which has operators ‘doing more with less.’
According to a recent Bloomberg article, current rig counts are less than half of what they were before the price crash in 2014. Analysts at Enercom estimate that modern rigs are delivering 3.15 times more production than those in January 2014.
It’s clear, however, that high oil prices will lead to more production with a cluster of smaller operators leading the way.
In the past six months, companies that aren’t among the top U.S. crude producers made up 42 percent of permits approved for new drilling, according to Drillinginfo in another Wall Street Journal article. Many of these operators have ambitious growth plans.
Ongoing Infrastructure Concerns
One potential constraint to such growth plans and production increases are bottlenecks in pipelines and other infrastructure to take the shale oil and gas to market.
As Drillinginfo discussed in a previous blog, such pipeline constraints are having an impact on both prices and supply. Spot crude from Midland, Texas in the heart of the Permian, for example, has been trading this week at almost $16 a barrel below the grade of oil in Houston – only 500 miles away – due to infrastructure issues. In such cases, it’s vital to get a complete overview of shale activities and midstream infrastructure in specific regions, as Drillinginfo provides.
As oil prices increase, however, so will the pressure to increase infrastructure and pipeline capacity as well as financial investment mechanisms for midstream projects, A number of significant midstream investments in the Permian are due to come online in the near future.
The continued rise in oil prices is good news for shale producers across the U.S., as they look to maximize the opportunities these prices bring. Furthermore, with U.S. and global demand remaining strong and declining global inventories, prices are likely to remain high over the coming months.
Against this backdrop, it’s more important than ever to access the latest decision-making intelligence for better and faster results, and increased profitability. That’s why operators choose Drillinginfo.
During Q2 2018, 28 bid rounds were identified as ongoing offering over 725,000 square kilometres of E&P acreage worldwide. To date, during the quarter 17 bid rounds in 6 countries have opened and 7 have closed. There are 9 estimated to open through the remainder of the quarter. Typically, each country promoting acreage provides a fiscal regime under which the areas can be licensed. Three regime types are used: Royalty/Tax, Production Sharing Contract (PSC), and Service Contract. However, in recent years a fourth hybrid regime, referred to as a Revenue Sharing (RS) regime has also been introduced.
NEW TENDERS ANNOUNCED
Egypt – EGPC 2018 International Bid Round
One of the most recent rounds to open is the Egyptian General Petroleum Corporation (EGPC) 2018 International Bid Round. The round launched on the 22 May 2018 and includes 11 blocks: seven of these blocks are located in the Western Desert, with the remaining four located in the Gulf of Suez. The round is scheduled to close on 1 October 2018 and the blocks are being offered under a PSC regime. The commercial parameters accompanying the round have been released and indicate that the blocks awarded in the round will have a 7-year maximum exploration period, followed by a Development Lease (DL) which will have a maximum duration of 30 years. EGPC will pay the contractor’s Royalty and Income Tax liabilities. The cost recovery ceiling is biddable but may not exceed 40% and amortisation of exploration and development expenses will be a minimum of four years. Operating costs are expensed. Contractor Profit Oil is a biddable parameter and is based on production tranches linked to the Brent Oil Price. EGPC’s share should not be less than 75% at a Brent Oil Price less than or equal to US$40/barrel and at a production rate of less than 5,000 bo/d. Higher oil prices and production levels require a State share of more than 75%. The State Share of Profit gas is also biddable based on daily production tranches. Any excess cost recovery is allocated 85% to the State. Additionally, several bonuses are also required including: Signature Bonus (competitive); Retention of Relinquished Area Bonus; Development Lease Bonus (minimum of US$100,000 per Development Block); Production Bonus (biddable and dependent on daily production rates); Five Years Extension Bonus (minimum US$5 million); Training Bonus (minimum US$100,000 annually); and an Assignment Bonus (which will be 10% of any transaction completed by the contractor and associated with the block).
Egyptian EGPC 2018 International Bid Round blocks
Norway – APA 2018 Bid Round
The largest round currently open is the Norwegian Awards in Predefined Areas (APA) 2018 Bid Round. The APA 2018 round opened on 9 May 2018 and offers 826 blocks covering over 225,000 sq km. For the 2018 release, 47 blocks in the Norwegian Sea and 56 blocks in the Barents Sea have been added to the previously available areas. The deadline for applications is 4 September 2018 and awards will be announced during Q1 2019. The APA rounds are held annually and apply to mature acreage on the Norwegian continental shelf. Previously in APA 2017, 75 licences totalling 21,748.5 sq km, were awarded to 34 companies.
Norwegian upstream oil and gas operations are governed through a Royalty/Tax regime. Acreage is awarded under a Production Licence which has a total length of 30 years; an extension of up to 30 additional years is also available. Royalties are not payable on oil production from fields where the development plan was approved after 1 January 1986. Additionally, the royalty rate effective since 1 January 1992 on gas production is zero percent. Instead a Special Petroleum Tax (SPT) at a rate of 55% is levied on gross revenue less exploration costs, operating costs, royalty, carbon dioxide tax, and depreciation of development costs. The SPT includes an extra allowance in the form of an uplift, which is 21.2% calculated at 5.3% over 4 years. Income tax at a rate of 23% is also applicable. In order to encourage new exploration in the area and support economically viable exploration the government introduced a reimbursement system in 2005. Under the system, companies making a loss can choose between requesting an immediate refund of the tax value of the exploration costs or carrying forward the losses to a later when the company has taxable income. Exploration costs under the immediate payment option are not deductible from income in later tax assessments.
Norwegian APA 2018 Bid Round blocks
Australia – 2018 Australia Offshore Petroleum Acreage Release
Additionally on 15 May 2018, the Australian Government released 21 new tender areas for the 2018 Australia Offshore Petroleum Acreage Release and seven re-released areas from the 2017 Australia Offshore Petroleum Acreage Release. Round 1 of this release is scheduled to close on 18 October 2018. In Australia upstream oil and gas operations are governed by location. Onshore and in state waters up to three nautical miles (~5.5km) offshore each state or territory has jurisdiction. Offshore beyond the three nautical mile limit the Federal government has jurisdiction.
The Australian Federal offshore area is governed under a royalty/tax regime through the Offshore Petroleum and Greenhouse Gas Storage Act 2006 and Federal tax legislation. A feature of the Australian fiscal regime is the use of the profit-based Petroleum Resource Rent Tax (PRRT) which was originally applied to Federal waters offshore, but which also applies onshore (and the Northwest Shelf Project area) from 1 July 2012. PRRT is a federal tax levied at a rate of 40% and is ring-fenced to individual petroleum projects. In 2017, there was political manoeuvres to alter the PRRT mechanism which advocated decreasing the uplift rates on exploration expenditure but the 2018 Federal budget, which was presented in May 2018, made no mention of any changes. However, despite the budget failure to address the PRRT uplift rates, industry is still of the belief that the PRRT uplift rates will be decreased in the medium term. The Corporate Income Tax rate is currently 30%.
Australian 2018 Australia Offshore Petroleum Acreage Release blocks
Ecuador – Ronda Intracampos 2018
Ecuador was initially planning to open the Ronda Intracampos licensing round in March 2018, however the country is now anticipating launching the round in June 2018. Eight blocks in the Oriente-Maranon Basin in the north east of the country will be available in the round and will be offered under a ‘Participation’ contract which is a PSC regime. Previously Ecuador has governed activities under a Service Contract regime. Bids will be evaluated primarily on the production share offered to the State and also on the total exploration investment committed (annual work commitment plans). The blocks on offer will be carved out of state-owned Petroamazonas acreage and have 13 undeveloped fields between them.
The Ecuadorian government is hoping to entice more oil companies to the new Intracampos round with the change in the fiscal framework. Under the new PSC regime, private companies can take their share of production in kind and therefore book reserves. This was not possible with the old Service Contract model. Previously in 2010, Ecuador converted all its previous contracts signed with foreign investors, including participation contracts (as PSCs are referred to as in Ecuador), marginal field contracts, and “old” Service Contracts, into a new type of Service Contract.
Ecuador’s Ronda Intracampos 2018 blocks
Dominican Republic – 2018 Dominican Republic Licensing Round
One of the rounds planned for Q3 2018 is the 2018 Dominican Republic (DR) licensing round. The DR has been working towards a licensing round since 2015 and initial plans include offering four blocks for exploration in two phases. During Phase 1, two blocks are expected to be issued: Azua (~13.4 sq km) and Enriquillo (~177 sq km). This release will be followed by a second tranche which will focus on the offshore in the Bay of Ocoa (~435 sq km) and the San Pedro de Macoris play (~7,922 sq km).
Both phases will be offered under a PSC regime. Pertinent terms from the model contract dated 26 March 2018 include a Special Tax on Hydrocarbons (IEH) which replaces Income Tax established in Law 11-92 of 16 May 1992. The IEH rate is based on an internal rate of return (IRR) calculation and adjusted by an additional amount bid by the contractor (X%). The IRR calculation is in four tranches (based on effective interest rate of Dominican Republic sovereign debt (Y%) and adjusted by 0% to 10% according to tranche) with rates of IEH between 40%+X% and 55%+X%. The maximum share of gross income available for cost recovery is 80%. Additionally, annual fees are required at four milestones within the project which are: First production – US$50,000, 0 to 30,000 boe/d – US$80,000, 30,001 to 50,000 boe/d – US$120,000, and greater than 50,001 – US$180,000.
2018 Dominican Republic Licensing Round blocks
On 27 March 2018, the Comision Nacional de Hidrocarburos (CNH) took bids for 35 exploration and extraction blocks in Mexico’s Round 3.1 (CNH-R03-L01/2017 over 2 areas: Burgos Basin, Tampico-Misantla-Veracruz Basin & Sureste (Southeast) Basin. There were 30 companies representing 6 continents that participated in the Bid Round (20 pre-qualified as operators and 10 non-operators) including BP, Shell, Chevron, & Total who just won blocks in the GOM 250 Lease Sale last week. Other participants include ENI, Pemex, Repsol, Lukoil & Premier Oil. In total, 16 areas were awarded in today’s Bid Round. Pemex came out the winner with the most areas awarded (4) totaling 2,935 sq km, plus they partnered up with 4 companies, including Shell & Total adding another 3 areas to their portfolio as a non-operator. Total is making a big push to be a leader in the GOM as they came out strong in the US GOM 250 lease sale last week winning 9 blocks, plus were awarded 3 areas today totaling 2,356 sq km.
Overall the Mexican government was excited about the results from the sale and the positive impact it will have on the country especially the competitive bidding on the Sureste (Southeast Basin).
Pre-3.1 Sale Overview
Prior to the 3.1 sale, Pemex had the most blocks (116) & acreage (~45,000 sq km). With Shell having the next highest block count (9) & acreage (~19,000 sq km) making them the boss in the GOM from the American and Mexican side (Figure 1).
Figure 1: Pre-Mexico 3.1 Offshore Round operator by block count and acreage. *Not shown: Pemex who has 116 blocks and over 45,000 sq km of acres they are the current operator making them the dominant operator in Mexico.
Bidding kicked off slow in Mexico City, with only four out of the 14 Burgos Basin blocks on offer getting snapped up. Repsol of Spain and UK-based Premier led the effort for this tranche of offshore shallow water blocks, separately picking up two tracks each. The Spanish company’s Repsol Exploración México secured rights to the 823 sq km Area 5 block with an additional royalty rate of 56.27%. That beat out state-run Pemex’s bid of 23.89%. Neither company offered additional investment factor. Meanwhile for Area 11, Premier Oil Exploration and Production Mexico scooped up the tract with its additional royalty bid of 29.43%. Premier was the sole bidder for the 396 sq m block. Repsol bid once more, scooping up Area 12. The company won the area with its 48.17% bid. The last block to be awarded, Area 13, went to Premier with its additional royalty payment bid of 34.73% The Burgos Basin blocks encompassed 8,424 sq km, with an estimated 579 MMboe in prospective resources.
Bidding for the second tranche of blocks in the Tampico-Misantla-Veracruz Basin was modest, with only four blocks out of 13 of the blocks on offer receiving any bids. Capricorn Energy with Citla Energy E&P won Area 15 (971 sq km in the Tampico-Misantla Basin) with an additional royalty bid of 27.88%. State-run Pemex Exploración y Producción with Deutsche Erdoel México and Compañía Española de Petróleos won Area 16 with their 24.23% bid. The trio followed up that win by offering an additional royalty if 35.51% for Area 17. Pemex, in a separate partnership with Spanish Compañía Española, bid an additional royalty of 40.51%, thus winning Area 18.
Bidding finally picked up the pace with the Sureste (Southeast) Basin with lots of partnerships and contested bidding for these 8 coveted areas. As the bids were announced you could feel the excitement transmitted from the Mexican government about the competitiveness & desire from companies to win awards in this hydrocarbon rich basin. In Area 28, Eni of Italy and Russian Lukoil came on strong with an aggressive bid of 65% with an investment factor of 1.5, and a tie-breaker cash bonus of US$ 59.823 million. That beat out the second highest bid from Deutsche with Premier. As for Area 29, Pemex submitted a winning bid of 65% with an additional investment factor of 1.5 and a US$ 13.07 million-plus bonus. In second place, Deutsche Erdoel México & partners lost out again offering 65% with an additional investment factor of 1. Bidding intensified for Area 30. Deutsche, Premier, and Sapura won this tract with their bid of 65%, an additional investment factor of 1.5, and a US$ 51 million-plus cash bonus. They won out over 6 other bids on this area making it the most competitive in the 3.1 Bid Round. Area 31 went to Pan American Energy, which bid an additional royalty of 65% with an additional investment factor of 1 while Total & Pemex won Area 32 with 40.49%. Area 34 was awarded to Total, BP and Pan American Energy with a bid of 50.49% and an investment factor of 1, and Area 35 closed out the awards going to Shell and Pemex with the winning bid of 34.86% for this block.
Figure 2 shows the results of the 3.1 Bid Round by award count and area (sq km). Pemex came out the top winner followed by Total. Premier Oil made a great showing walking away with 3 awards.
Figure 2: Mexico 3.1 Bid Round Results. Pemex was the top winner followed by Total and Premier.
Interested in learning more?
Please contact the DrillingInfo GOM Team:
Tom Liskey, Regional Mgr – Americas Tom.Liskey@drillinginfo.com
Robyn Marchand, Technical Advisor – DrillingInfo Robyn.Marchand@drillinginfo.com
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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.
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