OilVoice Magazine | March 2013
Content
Edition Twelve – March 2013
Super majors feel the pinch in 2012 The questionable logic of U.S. natural gas exports E & P in Libya following the revolution
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OilVoice Magazine | MARCH 2013
Adam Marmaras Chief Executive Officer Issue 12 – March 2013 OilVoice Acorn House 381 Midsummer Blvd Milton Keynes MK9 3HP Tel: +44 208 123 2237 Email: [email protected] Skype: oilvoicetalk Editor James Allen Email: [email protected] Director of Sales Terry O'Donnell Email: [email protected] Chief Executive Officer Adam Marmaras Email: [email protected] Social Network Facebook Twitter Google+ Linked In Read on your iPad
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Welcome to the 12th Edition of the
OilVoice Magazine. It's been a year since we launched, and I have to say the time has flown by. One risk in starting a magazine is being able to commit each month to producing an issue that contains articles of a consistent standard. Luckily, thanks to our roster of contributors, we've never had that problem. In fact, often it is the opposite. We have too much content and we have the tough decision of choosing what makes it into the magazine. Another part of the site doing well is the OilVoice Jobs board. A year ago we completely rebuilt it, giving it the features of other leading job portals. The investment paid off, and we now have 1000 active oil and gas jobs to browse through. If you're looking for a career move, it's a great place to start.
Happy reading
Adam Marmaras CEO OilVoice
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Contents
Featured Authors Biographies of this months featured authors After In Amenas - Risk and security in North Africa by Henry Jones-Davies Recent Company Profiles The most recent companies added to the OilVoice directory Drilling efficiency: Lowering the break-even price of natural gas by Keith Schaefer Turkey's Dadas Shale: One of the world's top unconventional shale oil plays by Jen Alic Invest in the Long Haul with Plains All American Pipeline by Robert Kientz The questionable logic of U.S. natural gas exports by Kurt Cobb When does UK employment law apply to overseas workers? - An employers' guide by Eric Gilligan and Claire Scott Super majors feel the pinch in 2012 by Eoin Coyne Insight: Celebrating Angola, celebrating explorers! by David Bamford E & P in Libya following the revolution by Matt Luheshi An unexpected surge in U.S. condensate production: From Eagle Ford to Canada by Keith Schaefer
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Featured Authors
Henry Jones-Davies LPD Risk Management Ltd.
Henry Jones-Davies is Managing Director at LPD Strategic Risk Ltd.
Keith Schaefer Oil & Gas Investments Bulletin
Keith Schaefer is the editor and publisher of the Oil & Gas Investments Bulletin. Keith reads many research reports, and does a lot of original research – call management teams, talking to contacts in the oil patch, scour company financials – to find the companies with the best chance to provide investor profits.
Jen Alic Oil & Gas Investments Bulletin
Jen Alic contributes articles to the Oil & Gas Investments Bulletin.
Kurt Cobb Resource Insights
Kurt Cobb is an author, speaker, and columnist focusing on energy and the environment. He is a regular contributor to the Energy Voices section of The Christian Science Monitor and author of the peak-oil-themed novel Prelude.
Robert Kientz The Drop Shadow
Robert has been an investor for many years and has 8 years experience working as a corporate auditor and 14 years corporate working experience.
Matt Luheshi Leptis E & P Ltd
Matt Luheshi is Director of Leptis E & P
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Eoin Coyne Evaluate Energy
Eoin Coyne is a lead M&A analyst for Evaluate Energy provides incisive commentary on the merger and acquisition activity for Oil & Gas Financial Journal through his Weekly Update posts.
Eric Gilligan Brodies LLP
Eric Gilligan is a partner of the Employment and Pensions Team, Brodies LLP, Aberdeen.
Claire Scott Brodies LLP
Claire Scott is an Associate of the Employment and Pensions Team, Brodies LLP.
David Bamford Finding Petroleum
David Bamford is 63. He is a non-executive director at Tullow Oil plc and has various roles with Parkmead Group plc, PARAS Ltd and New Eyes Exploration Ltd, and runs his own consultancy.
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After In Amenas - Risk and security in North Africa
Written by Henry Jones-Davies from Finding Petroleum Introduction: Most of the world's most valuable resources and therefore its dynamic growth markets are found in its highest-risk environments. Effective Risk Management is of paramount importance for organisations seeking to maximise their opportunities in these markets. This is the more so because the exploitation of these resources involves an intimate interchange between countries and governments with volatile political narratives and very high-risk environments. That is why, over the last century and a half a mutually beneficial relationship has developed between the oil and gas industry and the risk management or security sector. The attack: The attack on BP/Statoil gas installation at In Amenas/Teguentourine came as a wake-up call have served to sharpen the minds of the managements of all IOCs operating in North Africa. All the terrorists of the Al-Mulathameen Brigade a 'branded franchise' of AQIM, and presumably the elite of the Salafist-Jihadists in the Sahara/Sahel - were either killed or captured. The mission was a complete failure. The facility was not destroyed and will be made operational again in the near future. Despite the group's claims that the assault on In Amenas was triggered by the French intervention in Mali - which took place just a few days before - this was a carefully planned action which must have been several months in the making. During the 1990s the Algerian government declared that it had erected a 'ring of steel' around the oil and gas operations, and deployed substantial military resources to safeguarding what was, and remains, practically its only source of export income. As events have proved these stringent measures have been largely successful. On January 16th, approximately 100 soldiers or gendarmes were tasked with guarding the Teguentourine facility. Yet 30 plus terrorists were able to mount an attack with very limited resistance. And while the security forces were able defeat the terrorists over the course of a few days, it is clear that the Algerian authorities failed in their task of preventing such an assault in the first place. Was this because of incompetence, complacency, a lack of decent intelligence whether humint or sigint,
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or a combination of all of these? Algerian intelligence will have its contacts and informants in the remotest places and yet a column of technical vehicles managed to cross vast areas of desert with all the problems of supply, refuelling and movement managed not only to penetrate carefully zoned security areas straight through the so-called 'Ring of Steel'. As far as Libya is concerned, the situation is far more tenuous and fluid. While the Algerian army is generally a capable force with decades of experience in counterterrorist warfare, in Libya, the formation of a national army and any form of Oil Protection Force is at an embryonic stage. One could argue that a similar operation there at present would serve only to embarrass the government - simply because very few foreigners currently work in-country, and the ransom value and consequent international publicity would be low. Will there come a point where IOCs decide that the risks outweigh the rewards? Is the threat to safe operations in these countries increasing? And if so, at what point will it be no longer feasible to continue? David Cameron, supported last week by Tony Blair, speaks of a decades'-long struggle against a dangerous and growing enemy which poses a "large and existential threat". Is he right? Yet to date no known attacks or aborted attacks in the West have been linked directly to AQIM. Whatever cover the deserts and mountains of the Sahel/Sahara have provided armed groups in the past is disappearing fast. The on-going French military action in Mali and action by the Algerian security forces are increasing the pressure. Whatever the intent, the capability of AQIM to mount attacks in continental Europe remains very low. However much one disparages the idea of the 'war on terror', AQ has suffered a series of devastating blows over recent years. Numbers of its leaders have been killed and networks infiltrated and broken up. That is not to say that in whatever form they may appear Salafist-Jihadist groups do not constitute a real and formidable threat to international security. These groups constantly struggle to adapt themselves to new, less congenial operational environments. During this period there may well be a concentration of smaller scale attacks mostly against more accessible, softer targets. As military and government targets increase their protection levels, softer commercial targets become will become more attractive. Terrorists research their targets carefully to assess vulnerabilities and for authorities to become complacent. Therefore it is important for security specialists to select and prioritise targets from the terrorist's point of view. Some suggested solutions:
Enhanced security by the Algerian government with an urgent review of strategy. Better training, intelligence; better international co-operation and the judicious sharing of intelligence/information. More active contact with locals tribes (Tuaregs in Algeria, Tuaregs and Tebu in Libya) with proper concern for their needs and demands.
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For Libya - the ground-up building of an effective Oil Protection Force and its urgent deployment is of paramount importance. To pre-empt the possibility of 'Green on Blue' attacks we might learn from the experience of In Amenas/Teguentourine where inside help and infiltration was certainly evident, and consider detailed vetting of LN staff. This, it must be admitted, may prove problematic in largely tribal Muslim societies like Algeria and more particularly, Libya. Nevertheless it must be seriously considered. Better co-operation between IOCs themselves, their security departments and governments, enhanced SOPs, better intelligence gathering through humint, sigint and aerial surveillance strategies.
In conclusion: It will have come as a huge embarrassment to the Algerian government after so many years of proven and effective experience against exactly this sort of organisation. This is why they dealt with it in their own way to the chagrin and annoyance of Western governments used to a more 'academic' approach. It was a combination of brutal determination and pride, which, one has to have experienced the civil war of the 1990s fully to understand. The Salafist-Jihadist threat is real and continues but we must be realistic about effectiveness and capabilities. When the lessons of In Amenas/Teguentourine have been learned and the security departments of IOCs are reassured that enhanced security is properly prioritised and in place, then oil and gas operations in North Africa can continue as successfully in the future as they have in the past. If the lessons are learned, and they are lessons applicable to both Algeria and Libya, then the involvement of IOCs n both countries has a future. If not, only the bravest and the best insured will persevere. The price will be judged too high.
View more quality content from Finding Petroleum
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Recent Company Profiles
The OilVoice database has a diverse selection of company profiles, covering new start-up companies through to multi-national groups. Each of these profiles feature key data that allows users to focus on specific information or a full company report that can be accessed online or printed and reviewed later. Start your search today! Kelt Exploration Ltd.
Oil & Gas Kelt is a Calgary, Alberta, Canada-based oil and gas company focused on exploration, development and production of crude oil and natural gas resources, primarily in west central Alberta and northeastern British Columbia.
Kelt Exploration's OilVoice profile
West Texas Resources
Oil & Gas West Texas Resources, Inc. is a Texas based independent oil company engaged in secondary enhanced oil recovery projects, exploratory drilling, and production of crude oil, natural gas liquids and natural gas in the onshore United States.
West Texas Resources’ OilVoice profile
Western Refining Inc.
Service Western Refining is dedicated to fueling the lives of our customers, by supplying them with products that move them, fly them, feed them, and make their lives better.
Western Refining's OilVoice profile
Union Jack Oil
Oil & Gas Union Jack Oil plc joined the ISDX Growth Market in December 2012 as a vehicle to identify drilling, development and investment opportunities in the hydrocarbon sector.
Union Jack Oil's OilVoice profile
Polar Petroleum
Oil & Gas As an independent American oil and gas company, Polar Petroleum is focused on securing domestic energy solutions through the exploration, development and production of oil and natural gas in Alaska's proven North Slope region.
Polar Petroleum's OilVoice profile
Impact Oil & Gas
Oil & Gas Impact Oil & Gas has built a portfolio of underexplored blocks in geologically prospective frontier areas off southern Africa. The company has one of the largest holdings offshore South Africa [for a private company] which currently consists of 75,991 square kilometres. The board seek to further increase Impact's footprint in the region as the current portfolio is progressed and developed.
Impact Oil & Gas' OilVoice profile
GulfMark Offshore
Service
GulfMark owns, operates and manages a modern fleet of offshore support vessels that include: Platform Supply, Anchor Handling Towing Supply, Fast Supply/Crewboats and Specialty Vessels. Their primary business is marine transportation services in support of the upstream oil and gas industry.
GulfMark Offshore's OilVoice profile
Health, Safety, Environment and Risk Management
RPS Energy is a global multi-disciplinary consultancy, providing integrated technical, commercial and project management support services in the fields of geoscience, engineering and HS&E.
Contact James Blanchard T +44 (0) 20 7280 3200 E [email protected]
rpsgroup.com/energy
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Drilling efficiency: Lowering the breakeven price of natural gas
Written by Keith Schaefer from Oil & Gas Investments Bulletin Natural gas bulls keep pointing to the declining gas rig count in the US as a reason for a near-term turnaround to the upside in prices. The gas rig count in the US has dropped by more than half in the last 18 months, but production continues at record levels—around 63-64 billion cubic feet per day (bcf/d). Why is that? First, the stats: The February 15 Baker Hughes rig count—the Bible of the industry— showed the gas rig count at 421, the fifth-lowest in the current run down—that’s down from 1,600 in 2008, or almost a 75% drop. Just this last year the gas rig count has dropped 41%.
(You can find this chart each week here). There are two obvious reasons for this—one is that there is more “associated gas” with oil production, especially in Texas (not so much in North Dakota on a per well basis, but overall the Bakken is up around 1 bcf/d in gas now). But the big reason is drilling efficiency. When I go to conferences, I tell the crowd— fracking isn’t improving every year. It’s not improving every quarter. It’s improving every month. That shows up in the reduced time it takes to drill a well now, thanks to improvements in horizontal drilling techniques, and in the amount of gas each well is able get out of the formation—thanks to improvements in hydraulic fracturing.
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The problem is, few companies want to brag about how much they’re improving production, so hard statistics are hard to come by. In one of his blog posts last year, industry expert Rusty Braziel of RBN Energy published some statistics from Southwestern Energy, which provided in-depth numbers on its drilling operations in the Fayetteville shale in Arkansas and Oklahoma. Over the course of five years, the company’s average drilling time per well plunged from 17 days in 2007 to only 8 days in 2011, falling by more than half. In just one year from 2010 to 2011, drilling time dropped more than 27 percent. Over the same five-year period, the later length of wells grew by 82 percent, and initial production more than doubled, rising from 1.65 million cubic feet per day in 2007 to 3.3 million cubic feet per day in 2011. All the while, the cost per well hovered around the same level, dipping 4 percent from 2007 levels. So for the same costs, drilling rigs were producing more than twice as many wells, with more than double the initial production. That means the initial production additions per rig grew by 338 percent in half a decade. If the rest of the energy industry saw the same kinds of improvement over the same period, even while cutting rig counts by three-quarters from their 2008 peak, we would expect to see a modest rise in production from simple efficiency. These changes are not just coming over the course of years, either. Southwestern reported huge swings in IP rates even from quarter to quarter. Between the first and second quarters of 2009, average IP rates at the company’s wells rose 20.7 percent, and eight quarters out of five years saw an increase of at least 13.4 percent. And other companies have seen comparable improvements. As recently as the third quarter of 2012, exploration giant Anadarko reported a 14 percent year-over-year reduction in drilling costs, along with a 40 percent drop in completion time at its Marcellus operations. Future of Oil and Gas Goes Through Efficiency Others are not only pointing out drilling efficiencies, but say they will continue into the future. A report released last summer from Credit Suisse hinged its estimates of future American oil production on expected improvements in efficiency. Credit Suisse estimates that that drilling and completion times will fall by around 40 percent within the next decade as exploration companies become more familiar with new technology and new geology. Some of the newest emerging plays, particularly in California, would come closer to a 50 percent reduction. That amounts to a less dramatic improvement than that observed by Southwestern over the past five years, but it would still allow energy firms to increase well counts by 27 percent by 2016 with only an 11 percent rise in rig counts.
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The report also assumes steadily improving initial production, a trend that has already been observed in shale developments in North Dakota. Credit Suisse sees IP rates rising 21 percent over the numbers seen at the end of 2011. As positive as these numbers sound, Reuters reports that consulting firm Bernstein Research points out the obvious other side of the coin—efficiency is improving dramatically because fracking operations at present are highly inefficient. The firm released research last year suggesting that as many as half of all fracking stages contribute no additional production from a given well. In turn, the vast majority of all production – 80 percent – comes from only 20 percent of all fracking stages; yet another example of the somewhat infamous Pareto principle, commonly known as the 80/20 rule. Nansen Saleri, president and CEO of consulting firm Quantum Reservoir Impact, told the news source: “In a few years the techniques used today for fracking will be viewed as primitive.” So as investors watch the gas rig count with a perplexed face, the industry has been steadily reducing the cost of drilling, lowering the break-even price of natural gas— and disappointing the bulls.
View more quality content from Oil & Gas Investments Bulletin
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Turkey's Dadas Shale: One of the world's top unconventional shale oil plays
Written by Jen Alic from Oil & Gas Investments Bulletin In Part 1 of our story on Turkey, contributing editor Jen Alic reviewed the country’s intriguing onshore and offshore oil potential. Today in Part 2, we’ll look at where the Big Prize lies: the Dadas Shale—a huge unconventional shale play—and which Canadian-listed junior producers may be best positioned in this emerging play.- Keith The Dadas Shale has the size and most potential to ignite both Turkey’s energy sector and the stocks of the North American listed juniors there. It’s a geological look-alike to the Woodford and Eagle Ford shales in the US. This large shale is estimated to have more than 100 billion barrels of original oil in place (OOIP)—but nobody has produced large amounts of oil from it yet. In southeast Turkey, Dallas/Istanbul-based TransAtlantic Petroleum Ltd. (TNP-TSX; TAT-NYSE) has come closest, recently announcing two 500 bopd horizontal wells in a conventional reservoir (think of the old-style oil pools vs. the new shale, tight oil) in the Mardin formation, above and below the Dadas shale.
TransAtlantic and Calgary-based partner Valeura Energy Inc. (VLE-TSX) also drilled
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a successful 150 bopd horizontal well in the same formation to the west at Gaziantep. These horizontals are firsts for Turkey. That got everyone’s attention— that oil had to be sourced from a local rock. TransAtlantic and Valeura and their partners have also found oil in a new play in southeast Turkey in the Bedinan formation which is just below the Dadas Shale but oil is also sourced from the Dadas. This is relatively tight oil but a recent frac by TransAtlantic in the Bedinan has shown that production rates can be significantly improved. “In the last six month we started having success in the southeast oil plays,” says Chad Potter, VP Finance of TransAtlantic. “We’re coming at it from multi-play idea on each license; where there is stacked pay, all likely sourced from Dadas shale.” ‘Stacked pay’ is industry talk for several underground oil formations all on top of each other like blankets on a bed. This allows producers to drill off several horizontal wells at different depths from one surface location—lowering costs and making production more profitable. It’s what everyone is trying to do with shale plays in North America. Potter said in a recent interview with Natural Gas Europe that investors understand that Dadas could be a big international shale discovery. “Horizontal drilling and frac technology is changing the game in chasing oil in southeast Turkey,” said Jim McFarland, President and CEO of Valeura. “The Dadas Shale is a world-classsource rock that has fed giant fields across the Middle East and North Africa.” TransAtlantic, along with Calgary-based Anatolia Energy and Valeura, definitely need to reward shareholders. All three have had a spotty exploration record over the last two years, and all of their share prices have lost 75% of their value from two years ago. (To be fair, most junior international exploration stocks have done the same.) TransAtlantic’s next important well, the Bahar-2H, has already spud and is targeting the Bedinan formation, directly below the Dadas shale and the company plans to complete the well with a multi-stage frac. Anatolia Energy (AEE-TSXv) CFO Pat McGrath says their company is doing a production test into the Dadas shale in September, with what will likely be a twostage vertical frack. They’re hoping for as much as 50 bopd per frack stage as a goal to shoot for. Other operators are also into Dadas. Shell stepped back on to the scene in September 2012 in partnership with Turkey’s state-owned TPAO. Exxon Mobil is said to be seeking an opportunity in the Dadas. Potter, McGrath and McFarland are keen to point out that the majors’ return to Dadas means that they were right to focus their investment here—even though the payout will be a while in coming.
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“The greatest potential in Turkey is in the unconventional plays. Turkey is essentially in the same stage as the North American Basins were in 2002. These plays have completely changed the North American oil and gas sector,” McGrath says. “This is the only opportunity to make a large enough impact to reverse the declining oil production in Turkey. One thing holding back even more exploration in Turkey is lack of access to Turkey’s historical geological and production data. While Turkey has been exceptionally generous with foreign oil and gas companies—offering some of the “most attractive fiscal terms in the world,” says McGrath—it maintains a tight lease on data that could help unleash the shale bounty. With all the other pieces in place, the main question for the industry right now, says McGrath, is “how and when we will be able to access the old producing fields, now held by the National Oil Company. These fields hold great potential for re-activation using unconventional technology. In the meantime, the national oil company just maintains marginal production through conventional wellbores.” And this is what Transatlantic, Anatolia and Valeura are banking on. For all, there is a strong focus on the Dadas Shale and the Bedinan and Mardin formations. Both are in the southeast. For Potter it’s essential to look at this from the “eye of the North American unconventional attitude.” Do the markets agree? Well, not just yet. The markets are saying “prove that any of this works,” according to Potter. But lately, each time they unlock a bit of value they have unlocked a bit of the stock price, as the stock chart has started to turn positive. Turkey’s BIG FIND is yet to happen. But the Dadas Shale gives the country its best chance at igniting a staking and production boom that could rival what’s happened in the United States in the last five years. JUNIORS IN TURKEY–QUICK FACTS TRANSATLANTIC PETROLEUM LTD (TAT:AMEX) (TNP:TSX)
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Positives
Holds massive acreage in Turkey, Bulgaria and Romania (5.4 million acres— 4.3 million in Turkey which includes 57 onshore exploration licenses and 9 onshore production leases) The sale of its Viking International oilfield services this year raised $157.5 million, which went to pay off debt and improve financials. Production should pick up in the first quarter of 2013 in the Molla license, with another exploration well (Goksu-3H) naturally flowing as of late October 2012 and additional horizontal drilling planned. Fracture stimulation of the Bahar-1 exploration well should be under way before the end of this year. TransAtlantic owns 100% interest in Goksu-3H and Bahar-1 Four operated rigs running–two in the Thrace Basin and two in southeastern Turkey. Plans for an initial 88-well development program for the Tekirdag field area (over the next 3 years)
Negatives
Lot of shares out already Total net sales have declined slightly from Q2 to Q3
QUICK FACTS on VALEURA ENERGY INC (TSX: VLE)
Positives
Money raised at higher prices–$1.30/share Annualized cash flow from Turkish production of $11-12 million at current production rates Working capital surplus of more than $29 million No debt Non-operated partner in Turkey with TransAtlantic Interests in 23 leases and licenses in Turkey for a gross acreage of 2.2 MM Analysts expect Valeura to benefit in 2013 from multi-stage fracture treatments in vertical wells in these tight gas and conventional gas targets
Negatives
Q3 oil and gas sales down 15% from Q2 (largely due to slowing of drilling/fracking in Thrace Basin for evaluation of Q2 results)
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QUICK FACTS on ANATOLIA ENERGY CORP. (TSX.V:AEE) (PINK-BEEHF)
Positives
Has 11.6 billion barrels of original oil in place in Turkey; 47 million barrels of net unrisked prospective resources in Turkey Lots of acreage (1,16 million gross acres) Good acreage diversification in Turkey: 11 licenses in four play types, including conventional and unconventional Positive working capital balance; cash on hand Renewed interest in the Dadas Shale play by the majors may boost Anatolia’s prospects in this play 50% interest in the Dadas Shale play No debt
Negatives
Anatolia is banking a lot on the Dadas unconventional shale play, which is still in a very early stage of development No production yet
View more quality content from Oil & Gas Investments Bulletin
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OilVoice Magazine | MARCH 2013
Invest in the Long Haul with Plains All American Pipeline
Written by Robert Kientz from Drop Shadow In a previous series of energy-related articles, I discussed how the resurgence of natural gas would give us solid alternative to oil for transportation energy needs. In addition, natural gas will also provide us with additional supplies of petrochemicals to offset the world’s insatiable demand for them and their end products, which includes just about everything you might currently purchase at Walmart. The gas shale boom has come along just in time to offset declining cheap oil supplies and offer the US, in particular, the enviable position of net energy exporter of the future. Those who have excess energy tend to have stronger and more resilient long-term economies. In addition to boosting our prospects of economic stability based upon a solid foundation of domestic energy supplies, the boom in natural gas and oil production in the United States provides investors with many potential choices for stock appreciation and dividend plays. In this series of articles, I will present some companies across the natural gas sector that may profit investors handsomely for several years. I’ll begin by discussing a midstream energy company, Plains All American Pipeline, LP (PAA), and will weigh benefits versus the risks. Foundation Plains is a vertically integrated oil and gas midstream company providing facilities, supplies and logistics, and transportation. The company sports over $5 billion in portfolio across a range of assets. The company has over 19,000 miles of pipeline in North America as its largest transportation asset, and is beefing up rail transportation to address short term shortages with $1 billion in rail depot projects in the last several months. The segment also includes trucks, trailers, and barges.
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Facilities provide storage, terminals, and throughput services for oil, natural gas, LPG, and refined products. The segment also offers LPG fractionation and processing of natural gas. Supply and Logistics purchases product and resells it at the other end of their transportation networks. Plains dropped down their natural gas storage into a separate LP, PAA Natural Gas Storage (PNG), which I will discuss in a future article.
The recent purchase of BP’s Canadian NGL assets provides Plains with an opportunity to process and transport those products in Canadian to US markets, as well as using the infrastructure for moving other refined products that capture higher premiums on the market. Plains management expects their retail approach to raise margins on these former assets which BP used primarily for internal purposes.
Outside of the BP purchase, Plains has concentrated on expanding pipelines, storage, and rail at existing sites to take advantage of local market knowledge while
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reducing the risk of asset under-utilization. Plains management has positioned assets in active and sizeable oil and gas plays that should allow smooth monetization and provide solid returns for investors. The approach to Plains’ expansion is a solid one with real gains seen in each business segment. I believe that Plains business model closely aligns with growth in the oil and gas segments, specifically in pipelines and rail to markets and in fractionation of natural gas liquids. The company has a forward-thinking market approach and has appeared to spend their money wisely given current market trends. Business Risk In keeping with my risk-based approach to investing, the following is my analysis of the risks that Plains All American Pipleline faces in the market. First, the recent expenditures in rail appear to alleviate the near-term shortage of transportation needs to various markets. However, pipelines have a higher return over time and the industry is expected to invest very heavily in pipelines that will compete in some areas directly with Plains rail expansion. Determining what competition will arise is difficult as future demand volumes are in many cases difficult to predict accurately. Some of Plains’ rail may compete with pipelines and receive lower margins while some of it may sell at a premium due to lack of alternatives in the area. This is a chance that investors must take in assessing any of the midstream energy companies. Generally Plains has added rail where large pipeline alternatives do not exist to mitigate this risk, but it should not be expected that this scenario will hold true for all Plains future projects. One mitigating factor for the rail projects is that pipelines face political and environmental challenges that rail has tended to avoid thus far. Another is that pipelines are very costly, and rail can more quickly be implemented to support current market demand waiting on pipeline build out. Because US natural gas infrastructure is woefully behind, my instinct is that Plains will be fine. The rail expansion serves critical market needs and is profitable now. Likely it will be years before pipelines catch up to market demands and they may never meet all localized requirements for oil and gas products by themselves. Another risk for companies structured as MLPs are that most profits are distributed to the investors. As such, most expansion projects, being CAPEX intensive, are financed by share dilution and debt. Therefore, debt grades for PAA are one step above speculative. But I feel this rating is a bit misleading for those who understand how the sector operates in the long run. Normally I would warn away from companies that have relatively low operating margins and high debt levels, but in the case of energy MLPs I make an exception. I do not see many scenarios in a normal market hungry for grid power, transportation alternatives to rising oil costs, and cheap petrochemicals where income drops significantly for Plains and similar MLPs. Natural gas serves as a hedge for the trend
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of expensive oil and its byproducts and both products will experience strong demand. Plains’ assets should be slowly and methodically be monetized by the market. In addition, Plains targets a near 50-50 debt to equity ratio in order to keep finance options balanced. Too much share dilution will reduce distributions while too much debt may scare away lenders and investors wary of future liquidity issues. The financing balance targeted by Plains management has appeared to work as planned so far. Plains’ profits are fairly immune from market prices for oil, gas, and refined products because the company mostly operates as a toll road charging fees to various companies for transportation of the fuels. Certain parts of the company income including liquids re-sales, storage, and fractionation fluctuate by demand for a given product. Those portions of the Plains portfolio, however, make up a minority share of the income stream for the company. Profits and distributions should remain fairly consistent and independent of market prices in a normal market. Taxation One thing that must be mentioned with Master Limited Partnerships is that taxation for investors is treated differently by the IRS. Because income is not taxed twice, but passed down to investors, some of the income received from investment will be taxed at ordinary income tax rates and some will be taxed at capital gains rates. The National Association of Publicly Traded Partnerships has provided an easy to understand example of how MLPs are taxed.
Taxes are assessed yearly on net income per unit owned (which equals income minus depreciation taken by the partnership). A K1 will be issued to each investor for their yearly taxes which details what is taxable. In addition, upon sale of the asset, the investor is taxed yet again. Essentially, any depreciation deducted each year the MLP is owned will be ‘recaptured’ at sale at ordinary income tax rates. Capital gains are applied on the portion of cash distributions owing to growth in unit value. MLPs offer tax deferral of some taxation, but the taxation of recaptured depreciation
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at ordinary rates upon sale of the units can more than offset the tax deferral benefits depending on the unit yield (currently at 4.6% yearly for Plains) and holding time. Since the yield is taxed at the capital gains rate, MLPs which offer consistently rising yields over long time periods offer valuable tax shelters that may offset future ordinary income taxes for some investors. MLPs are a complicated investment vehicle for this reason, and each investor should consult with a tax professional before making any investment purchases to fully understand the tax implications. Financials As mentioned previously, Plains has a high debt to account for expansion, leading to a current ratio of 0.99.
Data courtesy of Yahoo Finance (finance.yahoo.com) Accounts receivables and inventories exceed accounts payable, but not all current liabilities. Therefore, we know that Plains All American will need to use some future net income to offset these liabilities. The good news is that all assets (minus goodwill) are substantially larger than liabilities. This suggests that Plains has
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created value through recent investment and will need to monetize developments into positive cash flow over time. Investors should expect operating margin to increase somewhat (beyond Q3 of 4.1 %) due to strategically placed expansion projects and the ability to add value with the BP Canadian NGL acquisition, based upon management guidance. The most important accounting metrics I look at are Book Value, Price / Book Value, and Enterprise Value EV / EBITDA. The first, currently at 18.65 per share, provides a basement value for the stock in the event several negatives earnings announcements lead the market to a fear of default, and the price drops. If earnings estimates are wrong and income falls precipitously for the company, inventors can generally expect to get something near book value for their stock at least. Plains trades at 2.83 times book ($52.78 price / $18.65 book value) which is not an unreasonable figure, but high for my tastes. The company trades at a 13.54 EV / EBITDA which is high for any company that I consider buying. It suggests the company is ‘worth’ 13.54 times earnings potential to shareholders and debtors. I usually do not go above a measure of 10 EV / EBITDA. Note that I am very conservative investor regarding valuations, and I don’t give much thought to competitor valuations in the same market. Too many times I have seen entire sectors become overvalued, rendering this analysis short-sighted and potentially dangerous. Investors may have jumped the gun on Plains All American, and I would wait for a pullback before entering. Analysts expect Plains to beat earnings on February 6th, and the stock has run pretty high on expectations of extensive future growth yet to occur. Rising income will eventually 1) pay down debt and cause the company to 2) repurchase shares as they have in the past, while 3) raising cash distributions for investors in the process. But Plains is in expansion mode and current valuations shouldn’t be supported in the near term. Technical Indicators The yearly chart for PAA tells us that a slow, orderly climb has been replaced with a hard uptick in anticipation of earning announcements. However, technical indicators such as Stochastic and MACD indicate a leveling off on average volume. Last month’s run wasn’t based upon long-term fundamentals. Even if earnings adhere to predictions, I expect the stock to retest the 50 day moving average around $45 per share. That could be your short-term entry point, a week or two after earnings are announced this week, which will
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allow reasonable yield moving forward. Long term, I see the stock price leveling off lower than $45 and I personally would not enter into a long position until EV / EBITDA roughly equals a 10 multiple. Investing in MLPs, due to taxation and nature of oil and gas infrastructure build out is a long term proposition. Investors should consider all factors before placing money on this bet.
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The questionable logic of U.S. natural gas exports
Written by Kurt Cobb from Resource Insights With U.S. natural gas production having risen more than 25 percent from its nadir in 2005, natural gas producers are pushing for an end to limits on U.S. natural gas exports. The growth in supplies comes primarily from previously inaccessible shale deposits deep in the Earth, a development that has convinced many people that the country is now entering a new era of natural gas abundance. Trouble is, the United States remains an importer of natural gas. Through November 2012 the country imported 12.5 percent of its natural gas consumption for the year, mostly from Canada. That's down from an average of 15.7 percent for the previous 20-year period. But it's not exactly energy independence. So worried are industrial consumers of natural gas about exports pushing up prices and thus their production costs that they've formed an alliance to fight the loosening of export restrictions. The alliance includes utilities dependent on natural gas to fuel electricity generation, chemical companies that use it as a feedstock for making myriad industrial chemicals, and heavy industrial users such Alcoa and Nucor who use natural gas to fire their metal-making operations. (Those who heat their homes and businesses with natural gas also stand to benefit if the alliance prevails.)
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The members of the alliance have reason to worry since Europeans are paying close to $12 per thousand cubic feet for liquefied natural gas and the Japanese are paying more than $17. Compare that to the U.S. domestic pipeline price for natural gas of just $3.27 as of last Friday (Henry Hub spot price). It's a classic case of those in an extractive industry seeking top dollar for their minerals, and those who buy the minerals to make other things seeking to keep a lid on the price of their inputs. Here in a nutshell is the logic on each side:
Natural gas producers believe they ought to have the right to sell production coming from under American soil to the highest bidder worldwide. They can't do that now because of U.S. export restrictions. Whether the United States produces enough natural gas for domestic consumption is actually irrelevant to this argument since it rests on the notion that the owners of the natural gas have the right in a free market to dispose of it as they wish. (For context, these same companies have been promoting the idea of American energy independence in the media in order gain public acquiescence to lax environmental regulation and support for opening public lands to more drilling. So much for energy independence!) The industrial consumers believe that there is a broader good to be served by keeping the prices of energy and chemical feedstocks low for domestic industries, and thereby giving those industries an advantage over competitors abroad. This translates into higher employment and income across wide areas of the American economy since low natural gas prices benefit practically every business and homeowner—everyone, in fact, who pays a natural gas bill. High natural gas prices, on the other hand, only benefit those in the natural gas production business while dampening activity in natural gas consuming industries and the economy in general.
But what if U.S. natural gas production does ultimately exceed U.S. consumption? Won't that make both sides happy? Actually not necessarily, because in a worldwide market for natural gas, every consumer is bidding against every other consumer. Even if U.S. domestic gas production does rise significantly from here, exporting it would make everyone in the United States subject to worldwide pricing pressures. Right now the U.S. exports small amounts of natural gas to Mexico and Canada in places where it makes economic sense to do so because of the proximity of American supplies. But, what the natural gas producers want is the development of a vast network export terminals that cool natural gas to -260 degrees F where it becomes a liquid that can be shipped overseas by special liquefied natural gas carriers. If that expansion proceeds far enough, it might bring U.S. natural gas prices to parity with world prices. If it doesn't proceed very far at all—perhaps due to pressure from the alliance of natural gas users mentioned above—then the producers may only see a slight rise in domestic natural gas prices beyond what they would have seen without such export terminals. All of this assumes that there will be plentiful supplies of natural gas in the United States. But, that might not be the case. U.S. natural gas production has been
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essentially flat for more than a year. Partly this is due to very low prices and subsequent cutbacks in drilling. But it belies the claim made in Congressional testimony by the industry's protagonist-in-chief, Chesapeake Energy CEO Aubrey McClendon, that supplies can grow 5 percent per year through 2018. While the industry still clings to the now widely discredited notion that the United States has a 100-year supply of natural gas (at current rates of consumption), new assessments have suggested vastly reduced numbers for the amount of U.S. natural gas from shale—the main source of new supplies—that is technically recoverable. In 2011 the U.S. Energy Information Administration, the statistical arm of the U.S. Department of Energy, reported 862 trillion cubic feet (tcf) in shale gas resources. In 2012 the agency revised the number downward dramatically to 482 tcf based on new information from the U.S. Geological Survey. Keep in mind that this number says nothing about whether such resources will beeconomically recoverable. That number is bound to be much smaller. Actual proven reserves of dry natural gas in the United States at the end of 2010 (the most recent date for which U.S. Department of Energy figures are available) amounted to about a 12-year supply at current rates of consumption. A reserve is something that can be produced profitably at today's prices with existing technology from known fields. As you will see, it is a much smaller amount when compared to "resources," a term in the oil and gas industry that really only refers to estimates based on sketchy evidence of what might be in the crust of the Earth under a country, state or field. Resources are never exploited to 100 percent, and often only a small fraction ever become reserves. Keep in mind that only 35 percent of all the oil ever discovered has actually been produced. The rest is too expensive and sometimes even impossible to extract. That's in fields we have drilled extensively! The percentage of an estimated resource that is likely to be extracted is often less than that because resource estimates have almost never been tested with an actual drill. Petroleum consultant Art Berman estimates that when all natural gas resources thought to be available under the United States are totaled, and an appropriate reduction is made based our experience with extraction, the actual economically recoverable resource of natural gas is likely to be closer to 23 years of supply at current rates of consumption, not exactly a figure that makes one confident about committing to send large quantities of natural gas abroad. Yet another thing to keep in mind is that none of the estimates discussed above contemplate increases in the rate of U.S. natural gas consumption, increases that natural gas producers have been promoting. The producers have suggested that there is enough natural gas to justify building a fleet of natural gas powered vehicles and increasing considerably electricity generation from natural gas (something that is already happening). If the rate of consumption were to increase each year, the time to the exhaustion of the presumed natural gas resource would shorten dramatically and the time to a peak in output followed by an irreversible decline would happen much, much sooner as well. Exactly what will we do with our new natural gas powered generating plants and vehicles if we experience a continuous decline in natural gas supplies, say, starting in 2025?
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Given all this it's surprising that industrial natural gas users are even considering accepting a compromise to allow a limited, but considerably higher volume of exports. U.S. shale gas resources—the biggest source of new supplies—continue to be a moving target, and their estimated size is moving swiftly downward. Possibly for that reason, the alliance of natural gas users mentioned above is suggesting that a decision about U.S. exports be delayed until a clearer picture of the country's natural gas endowment emerges. A Dow Chemical Company spokesman opined that if there really is a 100-year supply of natural gas under the United States, then we need not be in any rush to make a decision about exporting U.S.-produced gas. Kinda makes you wonder why all the natural gas producers are in such a hurry.
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When does UK employment law apply to overseas workers? An employers' guide
Written by Eric Gilligan and Claire Scott from Brodies LLP Despite recent attempts by the UK Government to shift the balance back in favour of the employer, the UK still boasts one of the most extensive systems of employment law, in terms of the protection it gives employees. An employer's obligations under the UK employment law regime are often more rigorous than those of foreign countries, certainly when compared to those beyond the European Union. This protection can extend not just to employees working within the UK but also to those working abroad, depending on the individual circumstances of the employment relationship. This issue was highlighted recently in a well-publicised case involving Halliburton, which decided that an 'international commuter' was covered by UK employment law. The Supreme Court decided that a Halliburton employee who worked in Libya on a '28 day on, 28 day off' basis was entitled to claim unfair dismissal because of a "sufficiently strong connection with Great Britain". This principle has been reinforced by a number of subsequent cases. Awareness of this area is crucial to UK-based employers in the oil and gas sector who frequently employ or engage people to work outside of the UK. Even where your business and employees are based abroad, if the employment relationship has a "sufficiently strong connection" with the UK, the individuals concerned could be covered by UK employment law. If you manage employees remotely it may be more difficult to ensure compliance with your obligations under UK law, potentially exposing your business to the risk of multiple claims relating to the various stands of discrimination as well as unfair dismissal. This means that some employers may wish to consider taking steps to minimise the chance of UK employment law applying to employees working abroad. Equally, some may want to be sure that UK law does apply. In Ravat v. Halliburton Manufacturing and Services Limited, the Supreme Court decided that Mr Ravat could bring his claim for unfair dismissal in the UK because his employment had a stronger connection with the UK than Libya, where he worked. Mr Ravat was employed as an accounts manager and commuted between his home in Preston and his job in Libya. His commuting costs were covered by his employer; his salary, tax and National Insurance contributions were paid in the UK; his contract
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stated it was governed by English law and his grievance had been dealt with by Halliburton's Aberdeen office. These factors were found to outweigh the fact that Mr Ravat always worked in Libya, reported to a manager in Cairo and did much of his work for the German branch of Halliburton. In a subsequent case involving a UK law firm, Clyde & Co LLP, the Court of Appeal decided that where an individual spent some time living or working in the UK (even a few weeks), that would be enough to show a sufficient connection to the UK. It was not necessary to take into consideration the factors pointing away from the UK, even where there were many, as in this case. The High Court has recently also allowed a claim by a group of pilots working for a company providing private jet hire across Europe, Netjets Management Limited. The claim to be recognised as a bargaining unit for collective bargaining purposes was successful because the pilots were able to show a sufficiently strong connection to the UK. The court was particularly influenced by the fact that the pilots' contractual terms relating to pay, hours and holidays were governed by English law. Whether an employee is protected by UK employment law will always depend on the individual circumstances of their employment. It is, however, possible to identify the following checklist of factors which will influence whether UK law applies:
The location of the employing company; Where management, HR functions, training and administration relating to the employee's work take place; Where pay, pensions, tax and National Insurance contributions are payable; The currency in which employees are paid; Whether the employer pays commuting or other related costs; The amount of time an employee spends in the UK to work, live or to undergo training; Whether legal references in the contract are consistent with the legal system said to be applicable; and Whether there is a clause in the contract dealing with where the parties anticipate legal claims should be raised;
While all these factors will be taken into account, they are not decisive and it is worth noting that the courts will look at the reality of the employment relationship in order to determine whether the connection with the UK is sufficiently strong to merit the protection of UK law. Employers who are thinking of implementing the measures necessary to exclude the applicability of UK law may want to weigh up the cost of this against the risk of potential claims that employees may be able to bring in the UK and any adverse employee relations issues which may arise.
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OilVoice Magazine | MARCH 2013
Super majors feel the pinch in 2012
Written by Eoin Coyne from Evaluate Energy The annual 2012 results of the major players in the global oil and gas industry are out and a distinct picture on how the year has progressed can now be formed. At the top of the food chain, the super majors - consisting of Exxon Mobil, Shell, Total, BP and Chevron - turned out a meagre performance with a 13% drop in earnings for the group as a whole. Of this group, only Exxon Mobil recorded a gain on earnings from the previous year. Trading conditions between 2011 and 2012 have remained very similar. Refining and marketing earnings are slightly higher on the back of higher margins and demand. The oil price, as per the WTI benchmark, has had a relatively steady performance, starting the year at $99, finishing at $92 and experiencing few supply or demand shocks in between. This is in contrast to gas prices that varied greatly in different areas of the world; The average US price fell 25% since last year (now less than $3/mcf) whilst prices for gas in Europe (over $11/mcf) and LNG cargoes to Asia (over $14/mcf) averaged much higher. The diversity in the operations of the major companies safeguarded their earnings from the US and Canadian gas prices to a large extent but the North American independents could do little to keep the situation from hitting their earnings. The impact on Encana and Talisman, two companies who are both strongly weighted towards gas production in North America, was for Encana to report the lowest net income in the company’s history and for Talisman to report its lowest annual income since 1999. The drop in earnings for the super major group can, in addition to the low North American gas realisations, be attributed to a fall in the production rate for the group as a whole. Oil and gas production has now dropped by 3% for the group for two years in a row. The earnings and production performance for the group may paint a slightly bleak picture of 2012 but this only tells one particular side of how 2012 fared for the oil industry. The credit crisis is becoming a more distant memory, the worries of further global economic depression never fully materialised and confidence in the industry is slowly building. This can be seen in total investments for the group, which are 37% higher than 2009 and 2% higher than 2011. All 5 companies in the group strengthened their balance sheets by decreasing net debt by 17% as a whole, with Exxon Mobil and Chevron now able to boast positive net debt positions.
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Net Income ExxonMobil Royal Dutch Shell Chevron Total BP 2011 41.1 30.9 26.9 17.2 25.7 2012 44.9 26.6 26.2 13.8 11.6
Growth 2012 9.3% (14.0%) (2.7%) (19.6%) (54.9%)
The Super majors in Focus Exxon Mobil continued its quiet dominance of their peer group with a 9.3% gain on earnings in 2011. The performance marks the third year in a row of year-on-year income rises for Exxon Mobil since the credit crisis hit the oil industry in 2009. Although the 2012 net income wasn’t enough to surpass the $45 billion that Exxon Mobil made in 2008 before the crisis took hold, the 2012 earnings per share was the largest in the company’s history, due to an extensive share buyback programme. There was little to separate the next two largest publicly traded companies, Royal Dutch Shell and Chevron. The two companies are remarkably similar in market capitalisation, weighting between their upstream and downstream segments and focus of their global operations and their respective net incomes for 2012 followed the same relationship, with reported earnings of $26.6 billion and $26.2 billion for the year. BP’s annus horribilis may have been over 2 years ago in 2010 with the Horizon rig explosion, but 2012 will be another year that the company will be happy to bid farewell to. The year included yet more repercussions from the disaster with further charges of $5 billion and the lower asset base from the large divestiture programme inevitably fed through to the earnings which suffered a 55% drop. Following the disaster and its ramifications, BP is now a very different company to the one it was 3 years ago and with Petrobras now surpassing BP in terms of enterprise value and annual investment, the lines of what constitutes the super major group may have to be redrawn in the near future.
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OilVoice Magazine | MARCH 2013
Insight: Celebrating Angola, celebrating explorers!
Written by David Bamford from Finding Petroleum Sometimes we explorers have a hard time, sometimes we have something to celebrate. So, over my career I have great memories of seeing the first logs from the Machar discovery in the North Sea, from Mars in the Gulf of Mexico, from Foinaven in the West of Shetlands, from Girassol in Angola, from Jubilee in Ghana, and so on. I emphasise that in these examples, sometimes I was ‘on the pitch’, others ‘sitting in the stands’. However, once in a while there are even bigger memory jolts, for example the other day when I saw that BP had announced first oil from Block 31 (the PSVM project) in Angola and that, according to Bob Dudley, BP group CEO, “Over the coming decade, we expect Angola, where we have extensive interests from exploration through to production, to be one of the main hubs delivering growth for BP”.
A view from a helicopter of BP's Plutao, Saturno, Venus and Marte (PSVM) Floating Production, Storage and Offloading (FPSO) vessel. Image owned by BP plc.
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My mind went back to 1995 when due to a kind of ‘domino effect’ of one person leaving the company, I became the leader of a small, fledgling, team attempting to build BP’s business in West Africa, especially Angola although we also had interests in Nigeria (and for a wee while in Mocambique). Within a week or so, I made my first discovery – that there were some determined opponents of our involvement in Angola, folk who saw risk not opportunity, who thought that the 3rd world, and Africa in particular, was a scary sort of place (in comparison with say the Gulf of Mexico, Alaska, the North Sea), and who tried very hard to get us to stop. I could never figure out whether this was xenophobia or maybe neophobia, or just intra-executive rivalry. You know who you are – for other interested parties, names will be supplied by e-mail! But my second discovery was that there were many supporters – John Browne, Rodney Chase, Chris Wright, Tony Hayward, Ian Vann - who made sure that we continued and had the resources that we needed, could call on support in Luanda (and Lagos) whenever we needed it, and so on. And finally I discovered that my small team had some great explorers in it – folk who became ‘legends’ in the company! You also know who you are! So we rolled forward through 1996, 1997 and into 1998, making discoveries in Block 17 and 15, appraising them, enjoying Shell’s failures in Block 16 (it is a competition after all!), encouraging the Angolan Ministry of Petroleum and Sonangol to offer new ultra deep water blocks, working with our partners (Elf and Exxon), culminating in a scary (for me!) few weeks early in 1998 when first of all I had to show up at the BP Group Chief Executive’s Committee with a $1bn+ Finance Memorandum for the FPSO-based development of Girassol followed by something almost as large for our access to the ultra deep water blocks, especially Block 31. Block 31 was awarded in May 1999 and BP now has interests in nine offshore Angola blocks (15, 17, 18, 19, 20, 24, 25, 26 and 31) with operatorship of four (18, 19, 24 and 31) and participation in Angola LNG. Quite a story! And of course I’m proud to have had a small part in it. But this article isn’t a display of hubris, or at least I hope not. My point is that exploration is highly creative, in some ways the true research activity of an oil & gas company, and oftentimes faces strong opposition, for example from engineers and accountants, who are given to saying things like “I don’t see the value proposition here!” to which the only response is “Yes, you don’t see it….but it’s there!” Thus a piece of Bob Dudley’s comment that I especially enjoyed was “PSVM is one of the largest subsea developments in the world and was one of BP’s key project start-ups for 2012 as we grow higher-margin production.” So fellow explorers, I will offer you my following modification of a saying attributed sometimes to Sun Tzu, sometimes to anonymous Japanese sources: "If you sit by the river long enough, you will see (the bodies of) your opponents float by.”
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Finally, I must pay a tribute to a true unsung hero of BP’s involvement in Angola, namely Dick Field, who for at least a decade was our ‘man In Luanda’ enduring bouts of malaria, the civil war, numerous disappointments, all the time building the relationships which delivered in the end.
View more quality content from Finding Petroleum
E & P in Libya following the revolution
Written by Matt Luheshi from Finding Petroleum The oil industry in Libya is now over 55 years old. It has a complex history starting in the days of the kingdom (1951 – 1969) and developed further under the Gaddafi regime (1969 – 2011). A simplistic but not unfair characterisation is that Libya has great world class potential that has been poorly resourced and developed – not through lack of dedication of the professionals in the industry but through neglect and mismanagement at a political level by the previous regime. Libya is a good example of the impact of politics on exploration history. The pace of exploration and exploitation show a clear imprint of the political environment created by the behaviour of the Gaddafi regime. This has very important consequences on perceptions of the stage of maturity exploration of Libya’s various basins. In spite of the recent renewal of exploration in Libya (since lifting of UN sanctions in 2003) Libya’s oil industry is still arguably immature.
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Exploration history Libya has a diverse and very rich set of working hydrocarbon basins, supported by distinctive geographic advantages. The discovered resource is ~60 bnboe (recoverable), of which ~50% has been produced to date. The ultimate resource is almost certainly very much higher than this figure (a figure of ~100 bnboe is not unreasonable – that Libya’s exploration is immature is a commonly held view). Current production capacity is ~1.6-1.8 mboed.
There is a complex legacy that needs to be managed. The elements are well known and include oil fields and infrastructure that are in decline. There is also a major exploration potential that is not being exploited as effectively as modern science allows. There are commercial agreements in place with diverse terms and with a wide spectrum of operators. The Libyan Revolution of 2011 was a tumultuous and momentous period for the country that has opened up great opportunities on the political, social and economic fronts. What could be the impact on the oil industry looking forward? This is the third major dramatic change in Libya’s political situation (creation of the Kingdom in 1951, Gaddafi’s military coup in 1969 and the popular revolution of 2011). Aspirations to create a democratic government will inevitably have an impact on how business gets done in Libya. The pressure for modernisation is powerful and is likely to lead to a more accommodative and cooperative governance structure for the industry in Libya. This paper discusses the opportunities and risks facing the country and its international oil industry partners. The opportunities are still world class. While the risks are numerous the new political context sets a positive environment and the emerging trends are pointing to establishment of a much more modern business
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orientated oil industry in the country. This will take time to establish and patience will be needed. Since the election of a democratic General National Congress in July 2012, a clear timetable has been laid out to develop a new constitution and national institutions. Whilst progress is being made, the many political tensions in the country and continuing difficult security situation have inevitably introduced delays. Recently a process for electing a constitutional assembly was announced. This assembly will be elected through a national vote. It is likely that the drafting of a new constitution will stretch into 2014. This will finally establish the governance framework of New Libya and the management of the oil and gas resource will be a major element. In the meantime existing oil and gas agreements will continue to operate; with any adjustments that are needed being made at an administrative level. The scale of the remaining hydrocarbon opportunity in Libya is world class. The effectiveness and efficiency of future exploitation of this resource depends critically on the new legal framework and executive institutions that Libya chooses to create. The technical risks and uncertainties are amenable to application of modern science and technology. There are no particular exceptional petro-technical risks. The country also has a clear and obvious geographic advantage. This, together with the general high quality of Libya’s crude, makes this opportunity technically very attractive indeed. The main issue looking forward surrounds political risks. Libya’s geo-political importance relative to Europe is such that a very large amount of international support is being deployed to help see the country safely through this transition. Given the generous support from the UN, regional governments and international NGOs, it is highly likely that the processes in place to deliver a new constitutional framework will play out in a positive way. Today the complex internal and regional dynamics express themselves as political risk and uncertainty. A number of scenarios for the future political state of the country are possible. The emergence of a constitutional democracy is probably the most likely. The shape of this is unclear given the difficult internal environment, but the general popular will is driving towards a democratic outcome. The potential for Libya to finally become one of the best oil and gas producers in the world is real. Some patience will be needed while the political dynamics play out.
View more quality content from Finding Petroleum
Finding big oil elds in East Africa ..onshore, yes, but are there any o shore?! London, 09 Apr 2013 Finding big oil & gas elds in South East Asia The Politics may overwhelm the Geoscience! London, 14 May 2013 Delivering well integrity How best to manage well integrity - errant technologies, new technologies? London, 22 May 2013 Developments with FPSO operations Better ways to make decisions about specifying and operating FPSOs London, 04 Jun 2013 Russia & the FSU - plenty of opportunities below ground, plenty of problems above ground! London, 18 Jun 2013 Exploiting deep water elds ....it's not as easy as explorers think! London, 19 Sep 2013 Exploring internationally for unconventional oil and gas ....... nding the "sweet spots" London, 02 Oct 2013
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An unexpected surge in U.S. condensate production: From Eagle Ford to Canada
Written by Keith Schaefer from Oil & Gas Investments Bulletin Investing in Condensate, Part I explained what this hot new commodity is; Part II outlined the bullish case for Canadian condensate demand, and in this third and final article on condensate, I review American efforts to move their glut of condensate north. Condensate is making uneconomic gas wells profitable for producers in the shale basins of northern BC and Alberta, and creating some great investment opportunities for informed investors. The reason condensate is king in Canada is that oil sands producers need piles of this light oil to dilute their heavy bitumen for transport, and Canadian production can’t keep up with demand. How long can this party last? Shale oil and gas basins in the United States are churning outcondensate, where demand is very limited. A glut is developing. That glut is needed up north, so infrastructure players are busy planning, permitting, and building pipelines to move America’s piles of condensate to the Canadian oil sands producers that need it. Once that happens, will condensate’s Canadian price premium evaporate? It’s an important question, as strong condensate prices are the only leg many Canadian gas producers have to stand on right now. America’s Unexpected Condensate Wealth The Shale Revolution has transformed America’s energy scene. After decades of decline, US oil production is again on the rise. The turnaround has been even more dramatic on the natural gas front: shale wealth has transformed the country from an importer to an exporter and pushed prices to historic lows. Condensate production is an unexpected sideshow of the shale phenomenon – but it is starting to steal some of the limelight because shale wells are producing just so much of it.
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Take the Eagle Ford shale basin, which stretches across much of south and east Texas. The basin’s tight sedimentary rocks contain a range of hydrocarbons: wells on the southeastern flank generally produce dry gas, wells in the middle produce gas, natural gas liquids (NGLs), and condensate, and wells to the northwest generate oil and condensate.Eagle Ford producers drilled their wells looking for oil or gas. Condensate was an unexpected bonus – but it now makes up as much as 40% of the hydrocarbons produced from the formation. Forecasters predict that total Eagle Ford oil output will reach 500,000 to 800,000 barrels per day (bpd) by 2020. A large number of those barrels – somewhere between 250,000 and 400,000 bpd – will be condensate. Compare that to 2011, when condensate production from the formation averaged 130,000 barrels per day. It means condensate production from Eagle Ford will likely grow by 150% in less than a decade. And Eagle Ford is just one of a slew of shale basins being drilled and fracked apace in the United States to produce oil, natural gas, NGLs, and condensate. It sounds great, right? Not only are shale basins producing the natural gas and crude oil expected, they are also churning out piles of condensate, a hydrocarbon mixture so light you could often pour it straight into your tractor. Condensate must be making US shale producers happy, right? Wrong. Condensate and US Refineries – A Poor Match Since it is produced alongside oil and since it is in fact oil, producers lump condensate with oil when reporting production volumes. As a result, it seems like US oil production is shooting through the roof. But while domestic output is certainly rising, lumping condensate in with crude is misleading because not every hydrocarbon molecule is created equal – especially through the eyes of a refinery. Half of America’s refineries lie along the Gulf Coast. With the ability to process 8 million barrels of crude oil every day, this industrial complex truly sets the tone for oil pricing across the country. And guess what? Gulf Coast refineries don’t like condensate. What Is This “Freak of Nature” Gas Play? In short, it has the best economics of any pure gas play I’ve ever seen in my life. And in this new briefing, I take you through, point by point, why I think this one natural gas stock, a pure play on gas, could be the single best trade in the sector – junior, intermediate or senior. Keep reading here to learn more…
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Refineries are picky beasts, each one only able to process crudes within a particular API range. The Gulf Coast army of refineries used to love light oil, but over the last 25 years the world burned through many of its high-quality deposits of light crude. That forced producers to shift towards heavier and sourer crudes. In response, US refineries invested billions in upgrades to be able to process these more complicated crudes. In fact, from 2005 to 2009 the US refining industry spent $47.6 billion on heavy oil upgrades. Then came the Shale Revolution. Fracking technology is the engine for America’s drive for increased energy independence. Suddenly producers were pumping good quality oil from shale basins across the continent.The refineries can handle shale oil. They cannot, however, handle muchcondensate. The only way to feed condensate into these medium and heavy oil refineries is to mix the light oilwith a heavier crude, to produce a mid-weight blend. But even that is not ideal, because it turns out a mixture of heavy oil and condensate does not produce the same products as a straight crude of similar weight. Specifically, a mixture of light condensate and heavy crude produces lots of very light products, such as naphtha, and little to none of the heavier and more valuable distillates used to make diesel and jet fuel. So, since a crude-condensate blend produces less valuable products than a straight crude of the same average weight, refiners discount the price they’re willing to pay for blends. The unexpected surge in condensate production has collided head-on with low demand from US refineries, resulting in poor pricing. In general, Gulf Coast crude marketers have been paying about $15 per barrel less for condensate than for the light crude it is produced alongside. Since it is cheaper than crude, refineries are buying some condensate and mixing it with heavier crudes for processing. The products are worth less but input costs are also lower, so it works out ok for refiners’ bottom lines. It does not, however, work out well for producers. Shale producers invest millions of dollars into each multi-stage frac well. They don’t want to sell half their production at a discount – they want buyers who are willing to pay top dollar for all this light, sweet condensate. Those buyers, as we learned last week, are north of the 49th parallel. Getting Condensate to Canada Canada needs condensate. US producers are flooded with the stuff and want to sell it to Canadian oil sands operators. The challenge is moving it. The only pipeline currently moving condensate from the US into Canada is Enbridge’s Southern Lights line, which runs from Illinois to Edmonton. It can move
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180,000 barrels per day, which can more than handle the 110,000 bpd of condensate being imported now and Enbridge is proposing an expansion.
The hard part, the bottleneck, is getting it to Patoka, where it can enter Southern Lights. Patoka, it turns out, is not particularly close to the biggest condensateproducing shale in the US, which is the Eagle Ford basin in Texas. There are ways. For example, Plains All American is using the Louisiana port of St James as a staging post to route Eagle Ford condensate into the Capline pipeline for shipment to Patoka. Others are using existing gathering networks to move condensate to Corpus Christi on the Texas Gulf Coast, where it is loaded onto barges and transported to St James. Magellan Midstream Partners and Copano Energy are taking this one step further, extending one of Copano’s pipes by 140 miles to Corpus Christi. That line should soon be moving 100,000 barrels of condensate a day. KINDER MORGAN’S PLANS Kinder Morgan is also working to establish itself as an Eagle Ford condensate shipper. Kinder is building a condensate pipeline that can move 300,000 bpd from the shale basin to the Houston area, which is already being used to capacity.From Houston, the condensate from Kinder’s line moves through the company’s Explorer pipeline to Hammond, Illinois. That’s progress, but Canada is still hundreds of kilometers away. To connect its system to Canada, Kinder has two plans: 1. Extend Explorer to connect with Enbridge’s Southern Lights—one ends and another starts in Illinois. That link should be in service by early 2014.
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2. The other is to connect Explorer to the Cochin pipeline. Cochin moves propane 1,900 miles west to east—from Alberta to Ontario—through the US, crossing the border in North Dakota and skirting south of the Great Lakes before re-entering Canada in Windsor. Propane volumes have been declining, so Kinder is proposing to reverse and expand part of Cochin—from east to west—to move 95,000 bpd of condensate from Illinois to Alberta. Industry support for the project is clear: when Kinder held an open season on its Cochin proposal, the company received binding commitments for 105% of the proposed capacity. US regulators approved the plan in October; Kinder is now awaiting word from Canadian regulators. If all goes according to plan, the reversed Cochin will start moving condensate from the Midwest into Canada by mid-2014. Plans from Kinder and Plains All American alone will increase Eagle Ford condensate capacity to Alberta by 170,000 bpd by the middle of 2014. Other pipeline projects are also in the works. Not willing to wait, some US producers moving their condensate to Canada by rail. The upgrades are coming, and all signs indicate that every condensate pipe in the works will be filled to the brim almost from day one. Even without much dedicated infrastructure, condensate sales from the US to Canada have skyrocketed in recent years. Every estimate is different, but some analysts estimate that US condensate exports to Canada have grown 1,000% in the last two years alone. CONCLUSION Condensate capacity from the US to Canada should increase dramatically—but it is over a year away. Oil and gas marketers in Alberta tell me oilsands production is rising fast enough to use a lot more condensate—but only time will tell if the market stays in balance, over-supplied, or under-supplied. There’s a lot riding on this equation for Canadian natural gas producers—strong condensate pricing is the only thing between a lot of them and bankruptcy.
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Super majors feel the pinch in 2012 The questionable logic of U.S. natural gas exports E & P in Libya following the revolution
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Adam Marmaras Chief Executive Officer Issue 12 – March 2013 OilVoice Acorn House 381 Midsummer Blvd Milton Keynes MK9 3HP Tel: +44 208 123 2237 Email: [email protected] Skype: oilvoicetalk Editor James Allen Email: [email protected] Director of Sales Terry O'Donnell Email: [email protected] Chief Executive Officer Adam Marmaras Email: [email protected] Social Network Facebook Twitter Google+ Linked In Read on your iPad
You can open PDF documents, such as a PDF attached to an email, with iBooks.
Welcome to the 12th Edition of the
OilVoice Magazine. It's been a year since we launched, and I have to say the time has flown by. One risk in starting a magazine is being able to commit each month to producing an issue that contains articles of a consistent standard. Luckily, thanks to our roster of contributors, we've never had that problem. In fact, often it is the opposite. We have too much content and we have the tough decision of choosing what makes it into the magazine. Another part of the site doing well is the OilVoice Jobs board. A year ago we completely rebuilt it, giving it the features of other leading job portals. The investment paid off, and we now have 1000 active oil and gas jobs to browse through. If you're looking for a career move, it's a great place to start.
Happy reading
Adam Marmaras CEO OilVoice
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Contents
Featured Authors Biographies of this months featured authors After In Amenas - Risk and security in North Africa by Henry Jones-Davies Recent Company Profiles The most recent companies added to the OilVoice directory Drilling efficiency: Lowering the break-even price of natural gas by Keith Schaefer Turkey's Dadas Shale: One of the world's top unconventional shale oil plays by Jen Alic Invest in the Long Haul with Plains All American Pipeline by Robert Kientz The questionable logic of U.S. natural gas exports by Kurt Cobb When does UK employment law apply to overseas workers? - An employers' guide by Eric Gilligan and Claire Scott Super majors feel the pinch in 2012 by Eoin Coyne Insight: Celebrating Angola, celebrating explorers! by David Bamford E & P in Libya following the revolution by Matt Luheshi An unexpected surge in U.S. condensate production: From Eagle Ford to Canada by Keith Schaefer
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Featured Authors
Henry Jones-Davies LPD Risk Management Ltd.
Henry Jones-Davies is Managing Director at LPD Strategic Risk Ltd.
Keith Schaefer Oil & Gas Investments Bulletin
Keith Schaefer is the editor and publisher of the Oil & Gas Investments Bulletin. Keith reads many research reports, and does a lot of original research – call management teams, talking to contacts in the oil patch, scour company financials – to find the companies with the best chance to provide investor profits.
Jen Alic Oil & Gas Investments Bulletin
Jen Alic contributes articles to the Oil & Gas Investments Bulletin.
Kurt Cobb Resource Insights
Kurt Cobb is an author, speaker, and columnist focusing on energy and the environment. He is a regular contributor to the Energy Voices section of The Christian Science Monitor and author of the peak-oil-themed novel Prelude.
Robert Kientz The Drop Shadow
Robert has been an investor for many years and has 8 years experience working as a corporate auditor and 14 years corporate working experience.
Matt Luheshi Leptis E & P Ltd
Matt Luheshi is Director of Leptis E & P
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Eoin Coyne Evaluate Energy
Eoin Coyne is a lead M&A analyst for Evaluate Energy provides incisive commentary on the merger and acquisition activity for Oil & Gas Financial Journal through his Weekly Update posts.
Eric Gilligan Brodies LLP
Eric Gilligan is a partner of the Employment and Pensions Team, Brodies LLP, Aberdeen.
Claire Scott Brodies LLP
Claire Scott is an Associate of the Employment and Pensions Team, Brodies LLP.
David Bamford Finding Petroleum
David Bamford is 63. He is a non-executive director at Tullow Oil plc and has various roles with Parkmead Group plc, PARAS Ltd and New Eyes Exploration Ltd, and runs his own consultancy.
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After In Amenas - Risk and security in North Africa
Written by Henry Jones-Davies from Finding Petroleum Introduction: Most of the world's most valuable resources and therefore its dynamic growth markets are found in its highest-risk environments. Effective Risk Management is of paramount importance for organisations seeking to maximise their opportunities in these markets. This is the more so because the exploitation of these resources involves an intimate interchange between countries and governments with volatile political narratives and very high-risk environments. That is why, over the last century and a half a mutually beneficial relationship has developed between the oil and gas industry and the risk management or security sector. The attack: The attack on BP/Statoil gas installation at In Amenas/Teguentourine came as a wake-up call have served to sharpen the minds of the managements of all IOCs operating in North Africa. All the terrorists of the Al-Mulathameen Brigade a 'branded franchise' of AQIM, and presumably the elite of the Salafist-Jihadists in the Sahara/Sahel - were either killed or captured. The mission was a complete failure. The facility was not destroyed and will be made operational again in the near future. Despite the group's claims that the assault on In Amenas was triggered by the French intervention in Mali - which took place just a few days before - this was a carefully planned action which must have been several months in the making. During the 1990s the Algerian government declared that it had erected a 'ring of steel' around the oil and gas operations, and deployed substantial military resources to safeguarding what was, and remains, practically its only source of export income. As events have proved these stringent measures have been largely successful. On January 16th, approximately 100 soldiers or gendarmes were tasked with guarding the Teguentourine facility. Yet 30 plus terrorists were able to mount an attack with very limited resistance. And while the security forces were able defeat the terrorists over the course of a few days, it is clear that the Algerian authorities failed in their task of preventing such an assault in the first place. Was this because of incompetence, complacency, a lack of decent intelligence whether humint or sigint,
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or a combination of all of these? Algerian intelligence will have its contacts and informants in the remotest places and yet a column of technical vehicles managed to cross vast areas of desert with all the problems of supply, refuelling and movement managed not only to penetrate carefully zoned security areas straight through the so-called 'Ring of Steel'. As far as Libya is concerned, the situation is far more tenuous and fluid. While the Algerian army is generally a capable force with decades of experience in counterterrorist warfare, in Libya, the formation of a national army and any form of Oil Protection Force is at an embryonic stage. One could argue that a similar operation there at present would serve only to embarrass the government - simply because very few foreigners currently work in-country, and the ransom value and consequent international publicity would be low. Will there come a point where IOCs decide that the risks outweigh the rewards? Is the threat to safe operations in these countries increasing? And if so, at what point will it be no longer feasible to continue? David Cameron, supported last week by Tony Blair, speaks of a decades'-long struggle against a dangerous and growing enemy which poses a "large and existential threat". Is he right? Yet to date no known attacks or aborted attacks in the West have been linked directly to AQIM. Whatever cover the deserts and mountains of the Sahel/Sahara have provided armed groups in the past is disappearing fast. The on-going French military action in Mali and action by the Algerian security forces are increasing the pressure. Whatever the intent, the capability of AQIM to mount attacks in continental Europe remains very low. However much one disparages the idea of the 'war on terror', AQ has suffered a series of devastating blows over recent years. Numbers of its leaders have been killed and networks infiltrated and broken up. That is not to say that in whatever form they may appear Salafist-Jihadist groups do not constitute a real and formidable threat to international security. These groups constantly struggle to adapt themselves to new, less congenial operational environments. During this period there may well be a concentration of smaller scale attacks mostly against more accessible, softer targets. As military and government targets increase their protection levels, softer commercial targets become will become more attractive. Terrorists research their targets carefully to assess vulnerabilities and for authorities to become complacent. Therefore it is important for security specialists to select and prioritise targets from the terrorist's point of view. Some suggested solutions:
Enhanced security by the Algerian government with an urgent review of strategy. Better training, intelligence; better international co-operation and the judicious sharing of intelligence/information. More active contact with locals tribes (Tuaregs in Algeria, Tuaregs and Tebu in Libya) with proper concern for their needs and demands.
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For Libya - the ground-up building of an effective Oil Protection Force and its urgent deployment is of paramount importance. To pre-empt the possibility of 'Green on Blue' attacks we might learn from the experience of In Amenas/Teguentourine where inside help and infiltration was certainly evident, and consider detailed vetting of LN staff. This, it must be admitted, may prove problematic in largely tribal Muslim societies like Algeria and more particularly, Libya. Nevertheless it must be seriously considered. Better co-operation between IOCs themselves, their security departments and governments, enhanced SOPs, better intelligence gathering through humint, sigint and aerial surveillance strategies.
In conclusion: It will have come as a huge embarrassment to the Algerian government after so many years of proven and effective experience against exactly this sort of organisation. This is why they dealt with it in their own way to the chagrin and annoyance of Western governments used to a more 'academic' approach. It was a combination of brutal determination and pride, which, one has to have experienced the civil war of the 1990s fully to understand. The Salafist-Jihadist threat is real and continues but we must be realistic about effectiveness and capabilities. When the lessons of In Amenas/Teguentourine have been learned and the security departments of IOCs are reassured that enhanced security is properly prioritised and in place, then oil and gas operations in North Africa can continue as successfully in the future as they have in the past. If the lessons are learned, and they are lessons applicable to both Algeria and Libya, then the involvement of IOCs n both countries has a future. If not, only the bravest and the best insured will persevere. The price will be judged too high.
View more quality content from Finding Petroleum
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Recent Company Profiles
The OilVoice database has a diverse selection of company profiles, covering new start-up companies through to multi-national groups. Each of these profiles feature key data that allows users to focus on specific information or a full company report that can be accessed online or printed and reviewed later. Start your search today! Kelt Exploration Ltd.
Oil & Gas Kelt is a Calgary, Alberta, Canada-based oil and gas company focused on exploration, development and production of crude oil and natural gas resources, primarily in west central Alberta and northeastern British Columbia.
Kelt Exploration's OilVoice profile
West Texas Resources
Oil & Gas West Texas Resources, Inc. is a Texas based independent oil company engaged in secondary enhanced oil recovery projects, exploratory drilling, and production of crude oil, natural gas liquids and natural gas in the onshore United States.
West Texas Resources’ OilVoice profile
Western Refining Inc.
Service Western Refining is dedicated to fueling the lives of our customers, by supplying them with products that move them, fly them, feed them, and make their lives better.
Western Refining's OilVoice profile
Union Jack Oil
Oil & Gas Union Jack Oil plc joined the ISDX Growth Market in December 2012 as a vehicle to identify drilling, development and investment opportunities in the hydrocarbon sector.
Union Jack Oil's OilVoice profile
Polar Petroleum
Oil & Gas As an independent American oil and gas company, Polar Petroleum is focused on securing domestic energy solutions through the exploration, development and production of oil and natural gas in Alaska's proven North Slope region.
Polar Petroleum's OilVoice profile
Impact Oil & Gas
Oil & Gas Impact Oil & Gas has built a portfolio of underexplored blocks in geologically prospective frontier areas off southern Africa. The company has one of the largest holdings offshore South Africa [for a private company] which currently consists of 75,991 square kilometres. The board seek to further increase Impact's footprint in the region as the current portfolio is progressed and developed.
Impact Oil & Gas' OilVoice profile
GulfMark Offshore
Service
GulfMark owns, operates and manages a modern fleet of offshore support vessels that include: Platform Supply, Anchor Handling Towing Supply, Fast Supply/Crewboats and Specialty Vessels. Their primary business is marine transportation services in support of the upstream oil and gas industry.
GulfMark Offshore's OilVoice profile
Health, Safety, Environment and Risk Management
RPS Energy is a global multi-disciplinary consultancy, providing integrated technical, commercial and project management support services in the fields of geoscience, engineering and HS&E.
Contact James Blanchard T +44 (0) 20 7280 3200 E [email protected]
rpsgroup.com/energy
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Drilling efficiency: Lowering the breakeven price of natural gas
Written by Keith Schaefer from Oil & Gas Investments Bulletin Natural gas bulls keep pointing to the declining gas rig count in the US as a reason for a near-term turnaround to the upside in prices. The gas rig count in the US has dropped by more than half in the last 18 months, but production continues at record levels—around 63-64 billion cubic feet per day (bcf/d). Why is that? First, the stats: The February 15 Baker Hughes rig count—the Bible of the industry— showed the gas rig count at 421, the fifth-lowest in the current run down—that’s down from 1,600 in 2008, or almost a 75% drop. Just this last year the gas rig count has dropped 41%.
(You can find this chart each week here). There are two obvious reasons for this—one is that there is more “associated gas” with oil production, especially in Texas (not so much in North Dakota on a per well basis, but overall the Bakken is up around 1 bcf/d in gas now). But the big reason is drilling efficiency. When I go to conferences, I tell the crowd— fracking isn’t improving every year. It’s not improving every quarter. It’s improving every month. That shows up in the reduced time it takes to drill a well now, thanks to improvements in horizontal drilling techniques, and in the amount of gas each well is able get out of the formation—thanks to improvements in hydraulic fracturing.
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The problem is, few companies want to brag about how much they’re improving production, so hard statistics are hard to come by. In one of his blog posts last year, industry expert Rusty Braziel of RBN Energy published some statistics from Southwestern Energy, which provided in-depth numbers on its drilling operations in the Fayetteville shale in Arkansas and Oklahoma. Over the course of five years, the company’s average drilling time per well plunged from 17 days in 2007 to only 8 days in 2011, falling by more than half. In just one year from 2010 to 2011, drilling time dropped more than 27 percent. Over the same five-year period, the later length of wells grew by 82 percent, and initial production more than doubled, rising from 1.65 million cubic feet per day in 2007 to 3.3 million cubic feet per day in 2011. All the while, the cost per well hovered around the same level, dipping 4 percent from 2007 levels. So for the same costs, drilling rigs were producing more than twice as many wells, with more than double the initial production. That means the initial production additions per rig grew by 338 percent in half a decade. If the rest of the energy industry saw the same kinds of improvement over the same period, even while cutting rig counts by three-quarters from their 2008 peak, we would expect to see a modest rise in production from simple efficiency. These changes are not just coming over the course of years, either. Southwestern reported huge swings in IP rates even from quarter to quarter. Between the first and second quarters of 2009, average IP rates at the company’s wells rose 20.7 percent, and eight quarters out of five years saw an increase of at least 13.4 percent. And other companies have seen comparable improvements. As recently as the third quarter of 2012, exploration giant Anadarko reported a 14 percent year-over-year reduction in drilling costs, along with a 40 percent drop in completion time at its Marcellus operations. Future of Oil and Gas Goes Through Efficiency Others are not only pointing out drilling efficiencies, but say they will continue into the future. A report released last summer from Credit Suisse hinged its estimates of future American oil production on expected improvements in efficiency. Credit Suisse estimates that that drilling and completion times will fall by around 40 percent within the next decade as exploration companies become more familiar with new technology and new geology. Some of the newest emerging plays, particularly in California, would come closer to a 50 percent reduction. That amounts to a less dramatic improvement than that observed by Southwestern over the past five years, but it would still allow energy firms to increase well counts by 27 percent by 2016 with only an 11 percent rise in rig counts.
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The report also assumes steadily improving initial production, a trend that has already been observed in shale developments in North Dakota. Credit Suisse sees IP rates rising 21 percent over the numbers seen at the end of 2011. As positive as these numbers sound, Reuters reports that consulting firm Bernstein Research points out the obvious other side of the coin—efficiency is improving dramatically because fracking operations at present are highly inefficient. The firm released research last year suggesting that as many as half of all fracking stages contribute no additional production from a given well. In turn, the vast majority of all production – 80 percent – comes from only 20 percent of all fracking stages; yet another example of the somewhat infamous Pareto principle, commonly known as the 80/20 rule. Nansen Saleri, president and CEO of consulting firm Quantum Reservoir Impact, told the news source: “In a few years the techniques used today for fracking will be viewed as primitive.” So as investors watch the gas rig count with a perplexed face, the industry has been steadily reducing the cost of drilling, lowering the break-even price of natural gas— and disappointing the bulls.
View more quality content from Oil & Gas Investments Bulletin
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Turkey's Dadas Shale: One of the world's top unconventional shale oil plays
Written by Jen Alic from Oil & Gas Investments Bulletin In Part 1 of our story on Turkey, contributing editor Jen Alic reviewed the country’s intriguing onshore and offshore oil potential. Today in Part 2, we’ll look at where the Big Prize lies: the Dadas Shale—a huge unconventional shale play—and which Canadian-listed junior producers may be best positioned in this emerging play.- Keith The Dadas Shale has the size and most potential to ignite both Turkey’s energy sector and the stocks of the North American listed juniors there. It’s a geological look-alike to the Woodford and Eagle Ford shales in the US. This large shale is estimated to have more than 100 billion barrels of original oil in place (OOIP)—but nobody has produced large amounts of oil from it yet. In southeast Turkey, Dallas/Istanbul-based TransAtlantic Petroleum Ltd. (TNP-TSX; TAT-NYSE) has come closest, recently announcing two 500 bopd horizontal wells in a conventional reservoir (think of the old-style oil pools vs. the new shale, tight oil) in the Mardin formation, above and below the Dadas shale.
TransAtlantic and Calgary-based partner Valeura Energy Inc. (VLE-TSX) also drilled
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a successful 150 bopd horizontal well in the same formation to the west at Gaziantep. These horizontals are firsts for Turkey. That got everyone’s attention— that oil had to be sourced from a local rock. TransAtlantic and Valeura and their partners have also found oil in a new play in southeast Turkey in the Bedinan formation which is just below the Dadas Shale but oil is also sourced from the Dadas. This is relatively tight oil but a recent frac by TransAtlantic in the Bedinan has shown that production rates can be significantly improved. “In the last six month we started having success in the southeast oil plays,” says Chad Potter, VP Finance of TransAtlantic. “We’re coming at it from multi-play idea on each license; where there is stacked pay, all likely sourced from Dadas shale.” ‘Stacked pay’ is industry talk for several underground oil formations all on top of each other like blankets on a bed. This allows producers to drill off several horizontal wells at different depths from one surface location—lowering costs and making production more profitable. It’s what everyone is trying to do with shale plays in North America. Potter said in a recent interview with Natural Gas Europe that investors understand that Dadas could be a big international shale discovery. “Horizontal drilling and frac technology is changing the game in chasing oil in southeast Turkey,” said Jim McFarland, President and CEO of Valeura. “The Dadas Shale is a world-classsource rock that has fed giant fields across the Middle East and North Africa.” TransAtlantic, along with Calgary-based Anatolia Energy and Valeura, definitely need to reward shareholders. All three have had a spotty exploration record over the last two years, and all of their share prices have lost 75% of their value from two years ago. (To be fair, most junior international exploration stocks have done the same.) TransAtlantic’s next important well, the Bahar-2H, has already spud and is targeting the Bedinan formation, directly below the Dadas shale and the company plans to complete the well with a multi-stage frac. Anatolia Energy (AEE-TSXv) CFO Pat McGrath says their company is doing a production test into the Dadas shale in September, with what will likely be a twostage vertical frack. They’re hoping for as much as 50 bopd per frack stage as a goal to shoot for. Other operators are also into Dadas. Shell stepped back on to the scene in September 2012 in partnership with Turkey’s state-owned TPAO. Exxon Mobil is said to be seeking an opportunity in the Dadas. Potter, McGrath and McFarland are keen to point out that the majors’ return to Dadas means that they were right to focus their investment here—even though the payout will be a while in coming.
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“The greatest potential in Turkey is in the unconventional plays. Turkey is essentially in the same stage as the North American Basins were in 2002. These plays have completely changed the North American oil and gas sector,” McGrath says. “This is the only opportunity to make a large enough impact to reverse the declining oil production in Turkey. One thing holding back even more exploration in Turkey is lack of access to Turkey’s historical geological and production data. While Turkey has been exceptionally generous with foreign oil and gas companies—offering some of the “most attractive fiscal terms in the world,” says McGrath—it maintains a tight lease on data that could help unleash the shale bounty. With all the other pieces in place, the main question for the industry right now, says McGrath, is “how and when we will be able to access the old producing fields, now held by the National Oil Company. These fields hold great potential for re-activation using unconventional technology. In the meantime, the national oil company just maintains marginal production through conventional wellbores.” And this is what Transatlantic, Anatolia and Valeura are banking on. For all, there is a strong focus on the Dadas Shale and the Bedinan and Mardin formations. Both are in the southeast. For Potter it’s essential to look at this from the “eye of the North American unconventional attitude.” Do the markets agree? Well, not just yet. The markets are saying “prove that any of this works,” according to Potter. But lately, each time they unlock a bit of value they have unlocked a bit of the stock price, as the stock chart has started to turn positive. Turkey’s BIG FIND is yet to happen. But the Dadas Shale gives the country its best chance at igniting a staking and production boom that could rival what’s happened in the United States in the last five years. JUNIORS IN TURKEY–QUICK FACTS TRANSATLANTIC PETROLEUM LTD (TAT:AMEX) (TNP:TSX)
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Positives
Holds massive acreage in Turkey, Bulgaria and Romania (5.4 million acres— 4.3 million in Turkey which includes 57 onshore exploration licenses and 9 onshore production leases) The sale of its Viking International oilfield services this year raised $157.5 million, which went to pay off debt and improve financials. Production should pick up in the first quarter of 2013 in the Molla license, with another exploration well (Goksu-3H) naturally flowing as of late October 2012 and additional horizontal drilling planned. Fracture stimulation of the Bahar-1 exploration well should be under way before the end of this year. TransAtlantic owns 100% interest in Goksu-3H and Bahar-1 Four operated rigs running–two in the Thrace Basin and two in southeastern Turkey. Plans for an initial 88-well development program for the Tekirdag field area (over the next 3 years)
Negatives
Lot of shares out already Total net sales have declined slightly from Q2 to Q3
QUICK FACTS on VALEURA ENERGY INC (TSX: VLE)
Positives
Money raised at higher prices–$1.30/share Annualized cash flow from Turkish production of $11-12 million at current production rates Working capital surplus of more than $29 million No debt Non-operated partner in Turkey with TransAtlantic Interests in 23 leases and licenses in Turkey for a gross acreage of 2.2 MM Analysts expect Valeura to benefit in 2013 from multi-stage fracture treatments in vertical wells in these tight gas and conventional gas targets
Negatives
Q3 oil and gas sales down 15% from Q2 (largely due to slowing of drilling/fracking in Thrace Basin for evaluation of Q2 results)
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QUICK FACTS on ANATOLIA ENERGY CORP. (TSX.V:AEE) (PINK-BEEHF)
Positives
Has 11.6 billion barrels of original oil in place in Turkey; 47 million barrels of net unrisked prospective resources in Turkey Lots of acreage (1,16 million gross acres) Good acreage diversification in Turkey: 11 licenses in four play types, including conventional and unconventional Positive working capital balance; cash on hand Renewed interest in the Dadas Shale play by the majors may boost Anatolia’s prospects in this play 50% interest in the Dadas Shale play No debt
Negatives
Anatolia is banking a lot on the Dadas unconventional shale play, which is still in a very early stage of development No production yet
View more quality content from Oil & Gas Investments Bulletin
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OilVoice Magazine | MARCH 2013
Invest in the Long Haul with Plains All American Pipeline
Written by Robert Kientz from Drop Shadow In a previous series of energy-related articles, I discussed how the resurgence of natural gas would give us solid alternative to oil for transportation energy needs. In addition, natural gas will also provide us with additional supplies of petrochemicals to offset the world’s insatiable demand for them and their end products, which includes just about everything you might currently purchase at Walmart. The gas shale boom has come along just in time to offset declining cheap oil supplies and offer the US, in particular, the enviable position of net energy exporter of the future. Those who have excess energy tend to have stronger and more resilient long-term economies. In addition to boosting our prospects of economic stability based upon a solid foundation of domestic energy supplies, the boom in natural gas and oil production in the United States provides investors with many potential choices for stock appreciation and dividend plays. In this series of articles, I will present some companies across the natural gas sector that may profit investors handsomely for several years. I’ll begin by discussing a midstream energy company, Plains All American Pipeline, LP (PAA), and will weigh benefits versus the risks. Foundation Plains is a vertically integrated oil and gas midstream company providing facilities, supplies and logistics, and transportation. The company sports over $5 billion in portfolio across a range of assets. The company has over 19,000 miles of pipeline in North America as its largest transportation asset, and is beefing up rail transportation to address short term shortages with $1 billion in rail depot projects in the last several months. The segment also includes trucks, trailers, and barges.
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Facilities provide storage, terminals, and throughput services for oil, natural gas, LPG, and refined products. The segment also offers LPG fractionation and processing of natural gas. Supply and Logistics purchases product and resells it at the other end of their transportation networks. Plains dropped down their natural gas storage into a separate LP, PAA Natural Gas Storage (PNG), which I will discuss in a future article.
The recent purchase of BP’s Canadian NGL assets provides Plains with an opportunity to process and transport those products in Canadian to US markets, as well as using the infrastructure for moving other refined products that capture higher premiums on the market. Plains management expects their retail approach to raise margins on these former assets which BP used primarily for internal purposes.
Outside of the BP purchase, Plains has concentrated on expanding pipelines, storage, and rail at existing sites to take advantage of local market knowledge while
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reducing the risk of asset under-utilization. Plains management has positioned assets in active and sizeable oil and gas plays that should allow smooth monetization and provide solid returns for investors. The approach to Plains’ expansion is a solid one with real gains seen in each business segment. I believe that Plains business model closely aligns with growth in the oil and gas segments, specifically in pipelines and rail to markets and in fractionation of natural gas liquids. The company has a forward-thinking market approach and has appeared to spend their money wisely given current market trends. Business Risk In keeping with my risk-based approach to investing, the following is my analysis of the risks that Plains All American Pipleline faces in the market. First, the recent expenditures in rail appear to alleviate the near-term shortage of transportation needs to various markets. However, pipelines have a higher return over time and the industry is expected to invest very heavily in pipelines that will compete in some areas directly with Plains rail expansion. Determining what competition will arise is difficult as future demand volumes are in many cases difficult to predict accurately. Some of Plains’ rail may compete with pipelines and receive lower margins while some of it may sell at a premium due to lack of alternatives in the area. This is a chance that investors must take in assessing any of the midstream energy companies. Generally Plains has added rail where large pipeline alternatives do not exist to mitigate this risk, but it should not be expected that this scenario will hold true for all Plains future projects. One mitigating factor for the rail projects is that pipelines face political and environmental challenges that rail has tended to avoid thus far. Another is that pipelines are very costly, and rail can more quickly be implemented to support current market demand waiting on pipeline build out. Because US natural gas infrastructure is woefully behind, my instinct is that Plains will be fine. The rail expansion serves critical market needs and is profitable now. Likely it will be years before pipelines catch up to market demands and they may never meet all localized requirements for oil and gas products by themselves. Another risk for companies structured as MLPs are that most profits are distributed to the investors. As such, most expansion projects, being CAPEX intensive, are financed by share dilution and debt. Therefore, debt grades for PAA are one step above speculative. But I feel this rating is a bit misleading for those who understand how the sector operates in the long run. Normally I would warn away from companies that have relatively low operating margins and high debt levels, but in the case of energy MLPs I make an exception. I do not see many scenarios in a normal market hungry for grid power, transportation alternatives to rising oil costs, and cheap petrochemicals where income drops significantly for Plains and similar MLPs. Natural gas serves as a hedge for the trend
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of expensive oil and its byproducts and both products will experience strong demand. Plains’ assets should be slowly and methodically be monetized by the market. In addition, Plains targets a near 50-50 debt to equity ratio in order to keep finance options balanced. Too much share dilution will reduce distributions while too much debt may scare away lenders and investors wary of future liquidity issues. The financing balance targeted by Plains management has appeared to work as planned so far. Plains’ profits are fairly immune from market prices for oil, gas, and refined products because the company mostly operates as a toll road charging fees to various companies for transportation of the fuels. Certain parts of the company income including liquids re-sales, storage, and fractionation fluctuate by demand for a given product. Those portions of the Plains portfolio, however, make up a minority share of the income stream for the company. Profits and distributions should remain fairly consistent and independent of market prices in a normal market. Taxation One thing that must be mentioned with Master Limited Partnerships is that taxation for investors is treated differently by the IRS. Because income is not taxed twice, but passed down to investors, some of the income received from investment will be taxed at ordinary income tax rates and some will be taxed at capital gains rates. The National Association of Publicly Traded Partnerships has provided an easy to understand example of how MLPs are taxed.
Taxes are assessed yearly on net income per unit owned (which equals income minus depreciation taken by the partnership). A K1 will be issued to each investor for their yearly taxes which details what is taxable. In addition, upon sale of the asset, the investor is taxed yet again. Essentially, any depreciation deducted each year the MLP is owned will be ‘recaptured’ at sale at ordinary income tax rates. Capital gains are applied on the portion of cash distributions owing to growth in unit value. MLPs offer tax deferral of some taxation, but the taxation of recaptured depreciation
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at ordinary rates upon sale of the units can more than offset the tax deferral benefits depending on the unit yield (currently at 4.6% yearly for Plains) and holding time. Since the yield is taxed at the capital gains rate, MLPs which offer consistently rising yields over long time periods offer valuable tax shelters that may offset future ordinary income taxes for some investors. MLPs are a complicated investment vehicle for this reason, and each investor should consult with a tax professional before making any investment purchases to fully understand the tax implications. Financials As mentioned previously, Plains has a high debt to account for expansion, leading to a current ratio of 0.99.
Data courtesy of Yahoo Finance (finance.yahoo.com) Accounts receivables and inventories exceed accounts payable, but not all current liabilities. Therefore, we know that Plains All American will need to use some future net income to offset these liabilities. The good news is that all assets (minus goodwill) are substantially larger than liabilities. This suggests that Plains has
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created value through recent investment and will need to monetize developments into positive cash flow over time. Investors should expect operating margin to increase somewhat (beyond Q3 of 4.1 %) due to strategically placed expansion projects and the ability to add value with the BP Canadian NGL acquisition, based upon management guidance. The most important accounting metrics I look at are Book Value, Price / Book Value, and Enterprise Value EV / EBITDA. The first, currently at 18.65 per share, provides a basement value for the stock in the event several negatives earnings announcements lead the market to a fear of default, and the price drops. If earnings estimates are wrong and income falls precipitously for the company, inventors can generally expect to get something near book value for their stock at least. Plains trades at 2.83 times book ($52.78 price / $18.65 book value) which is not an unreasonable figure, but high for my tastes. The company trades at a 13.54 EV / EBITDA which is high for any company that I consider buying. It suggests the company is ‘worth’ 13.54 times earnings potential to shareholders and debtors. I usually do not go above a measure of 10 EV / EBITDA. Note that I am very conservative investor regarding valuations, and I don’t give much thought to competitor valuations in the same market. Too many times I have seen entire sectors become overvalued, rendering this analysis short-sighted and potentially dangerous. Investors may have jumped the gun on Plains All American, and I would wait for a pullback before entering. Analysts expect Plains to beat earnings on February 6th, and the stock has run pretty high on expectations of extensive future growth yet to occur. Rising income will eventually 1) pay down debt and cause the company to 2) repurchase shares as they have in the past, while 3) raising cash distributions for investors in the process. But Plains is in expansion mode and current valuations shouldn’t be supported in the near term. Technical Indicators The yearly chart for PAA tells us that a slow, orderly climb has been replaced with a hard uptick in anticipation of earning announcements. However, technical indicators such as Stochastic and MACD indicate a leveling off on average volume. Last month’s run wasn’t based upon long-term fundamentals. Even if earnings adhere to predictions, I expect the stock to retest the 50 day moving average around $45 per share. That could be your short-term entry point, a week or two after earnings are announced this week, which will
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allow reasonable yield moving forward. Long term, I see the stock price leveling off lower than $45 and I personally would not enter into a long position until EV / EBITDA roughly equals a 10 multiple. Investing in MLPs, due to taxation and nature of oil and gas infrastructure build out is a long term proposition. Investors should consider all factors before placing money on this bet.
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The questionable logic of U.S. natural gas exports
Written by Kurt Cobb from Resource Insights With U.S. natural gas production having risen more than 25 percent from its nadir in 2005, natural gas producers are pushing for an end to limits on U.S. natural gas exports. The growth in supplies comes primarily from previously inaccessible shale deposits deep in the Earth, a development that has convinced many people that the country is now entering a new era of natural gas abundance. Trouble is, the United States remains an importer of natural gas. Through November 2012 the country imported 12.5 percent of its natural gas consumption for the year, mostly from Canada. That's down from an average of 15.7 percent for the previous 20-year period. But it's not exactly energy independence. So worried are industrial consumers of natural gas about exports pushing up prices and thus their production costs that they've formed an alliance to fight the loosening of export restrictions. The alliance includes utilities dependent on natural gas to fuel electricity generation, chemical companies that use it as a feedstock for making myriad industrial chemicals, and heavy industrial users such Alcoa and Nucor who use natural gas to fire their metal-making operations. (Those who heat their homes and businesses with natural gas also stand to benefit if the alliance prevails.)
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The members of the alliance have reason to worry since Europeans are paying close to $12 per thousand cubic feet for liquefied natural gas and the Japanese are paying more than $17. Compare that to the U.S. domestic pipeline price for natural gas of just $3.27 as of last Friday (Henry Hub spot price). It's a classic case of those in an extractive industry seeking top dollar for their minerals, and those who buy the minerals to make other things seeking to keep a lid on the price of their inputs. Here in a nutshell is the logic on each side:
Natural gas producers believe they ought to have the right to sell production coming from under American soil to the highest bidder worldwide. They can't do that now because of U.S. export restrictions. Whether the United States produces enough natural gas for domestic consumption is actually irrelevant to this argument since it rests on the notion that the owners of the natural gas have the right in a free market to dispose of it as they wish. (For context, these same companies have been promoting the idea of American energy independence in the media in order gain public acquiescence to lax environmental regulation and support for opening public lands to more drilling. So much for energy independence!) The industrial consumers believe that there is a broader good to be served by keeping the prices of energy and chemical feedstocks low for domestic industries, and thereby giving those industries an advantage over competitors abroad. This translates into higher employment and income across wide areas of the American economy since low natural gas prices benefit practically every business and homeowner—everyone, in fact, who pays a natural gas bill. High natural gas prices, on the other hand, only benefit those in the natural gas production business while dampening activity in natural gas consuming industries and the economy in general.
But what if U.S. natural gas production does ultimately exceed U.S. consumption? Won't that make both sides happy? Actually not necessarily, because in a worldwide market for natural gas, every consumer is bidding against every other consumer. Even if U.S. domestic gas production does rise significantly from here, exporting it would make everyone in the United States subject to worldwide pricing pressures. Right now the U.S. exports small amounts of natural gas to Mexico and Canada in places where it makes economic sense to do so because of the proximity of American supplies. But, what the natural gas producers want is the development of a vast network export terminals that cool natural gas to -260 degrees F where it becomes a liquid that can be shipped overseas by special liquefied natural gas carriers. If that expansion proceeds far enough, it might bring U.S. natural gas prices to parity with world prices. If it doesn't proceed very far at all—perhaps due to pressure from the alliance of natural gas users mentioned above—then the producers may only see a slight rise in domestic natural gas prices beyond what they would have seen without such export terminals. All of this assumes that there will be plentiful supplies of natural gas in the United States. But, that might not be the case. U.S. natural gas production has been
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essentially flat for more than a year. Partly this is due to very low prices and subsequent cutbacks in drilling. But it belies the claim made in Congressional testimony by the industry's protagonist-in-chief, Chesapeake Energy CEO Aubrey McClendon, that supplies can grow 5 percent per year through 2018. While the industry still clings to the now widely discredited notion that the United States has a 100-year supply of natural gas (at current rates of consumption), new assessments have suggested vastly reduced numbers for the amount of U.S. natural gas from shale—the main source of new supplies—that is technically recoverable. In 2011 the U.S. Energy Information Administration, the statistical arm of the U.S. Department of Energy, reported 862 trillion cubic feet (tcf) in shale gas resources. In 2012 the agency revised the number downward dramatically to 482 tcf based on new information from the U.S. Geological Survey. Keep in mind that this number says nothing about whether such resources will beeconomically recoverable. That number is bound to be much smaller. Actual proven reserves of dry natural gas in the United States at the end of 2010 (the most recent date for which U.S. Department of Energy figures are available) amounted to about a 12-year supply at current rates of consumption. A reserve is something that can be produced profitably at today's prices with existing technology from known fields. As you will see, it is a much smaller amount when compared to "resources," a term in the oil and gas industry that really only refers to estimates based on sketchy evidence of what might be in the crust of the Earth under a country, state or field. Resources are never exploited to 100 percent, and often only a small fraction ever become reserves. Keep in mind that only 35 percent of all the oil ever discovered has actually been produced. The rest is too expensive and sometimes even impossible to extract. That's in fields we have drilled extensively! The percentage of an estimated resource that is likely to be extracted is often less than that because resource estimates have almost never been tested with an actual drill. Petroleum consultant Art Berman estimates that when all natural gas resources thought to be available under the United States are totaled, and an appropriate reduction is made based our experience with extraction, the actual economically recoverable resource of natural gas is likely to be closer to 23 years of supply at current rates of consumption, not exactly a figure that makes one confident about committing to send large quantities of natural gas abroad. Yet another thing to keep in mind is that none of the estimates discussed above contemplate increases in the rate of U.S. natural gas consumption, increases that natural gas producers have been promoting. The producers have suggested that there is enough natural gas to justify building a fleet of natural gas powered vehicles and increasing considerably electricity generation from natural gas (something that is already happening). If the rate of consumption were to increase each year, the time to the exhaustion of the presumed natural gas resource would shorten dramatically and the time to a peak in output followed by an irreversible decline would happen much, much sooner as well. Exactly what will we do with our new natural gas powered generating plants and vehicles if we experience a continuous decline in natural gas supplies, say, starting in 2025?
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Given all this it's surprising that industrial natural gas users are even considering accepting a compromise to allow a limited, but considerably higher volume of exports. U.S. shale gas resources—the biggest source of new supplies—continue to be a moving target, and their estimated size is moving swiftly downward. Possibly for that reason, the alliance of natural gas users mentioned above is suggesting that a decision about U.S. exports be delayed until a clearer picture of the country's natural gas endowment emerges. A Dow Chemical Company spokesman opined that if there really is a 100-year supply of natural gas under the United States, then we need not be in any rush to make a decision about exporting U.S.-produced gas. Kinda makes you wonder why all the natural gas producers are in such a hurry.
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OilVoice Magazine | MARCH 2013
When does UK employment law apply to overseas workers? An employers' guide
Written by Eric Gilligan and Claire Scott from Brodies LLP Despite recent attempts by the UK Government to shift the balance back in favour of the employer, the UK still boasts one of the most extensive systems of employment law, in terms of the protection it gives employees. An employer's obligations under the UK employment law regime are often more rigorous than those of foreign countries, certainly when compared to those beyond the European Union. This protection can extend not just to employees working within the UK but also to those working abroad, depending on the individual circumstances of the employment relationship. This issue was highlighted recently in a well-publicised case involving Halliburton, which decided that an 'international commuter' was covered by UK employment law. The Supreme Court decided that a Halliburton employee who worked in Libya on a '28 day on, 28 day off' basis was entitled to claim unfair dismissal because of a "sufficiently strong connection with Great Britain". This principle has been reinforced by a number of subsequent cases. Awareness of this area is crucial to UK-based employers in the oil and gas sector who frequently employ or engage people to work outside of the UK. Even where your business and employees are based abroad, if the employment relationship has a "sufficiently strong connection" with the UK, the individuals concerned could be covered by UK employment law. If you manage employees remotely it may be more difficult to ensure compliance with your obligations under UK law, potentially exposing your business to the risk of multiple claims relating to the various stands of discrimination as well as unfair dismissal. This means that some employers may wish to consider taking steps to minimise the chance of UK employment law applying to employees working abroad. Equally, some may want to be sure that UK law does apply. In Ravat v. Halliburton Manufacturing and Services Limited, the Supreme Court decided that Mr Ravat could bring his claim for unfair dismissal in the UK because his employment had a stronger connection with the UK than Libya, where he worked. Mr Ravat was employed as an accounts manager and commuted between his home in Preston and his job in Libya. His commuting costs were covered by his employer; his salary, tax and National Insurance contributions were paid in the UK; his contract
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stated it was governed by English law and his grievance had been dealt with by Halliburton's Aberdeen office. These factors were found to outweigh the fact that Mr Ravat always worked in Libya, reported to a manager in Cairo and did much of his work for the German branch of Halliburton. In a subsequent case involving a UK law firm, Clyde & Co LLP, the Court of Appeal decided that where an individual spent some time living or working in the UK (even a few weeks), that would be enough to show a sufficient connection to the UK. It was not necessary to take into consideration the factors pointing away from the UK, even where there were many, as in this case. The High Court has recently also allowed a claim by a group of pilots working for a company providing private jet hire across Europe, Netjets Management Limited. The claim to be recognised as a bargaining unit for collective bargaining purposes was successful because the pilots were able to show a sufficiently strong connection to the UK. The court was particularly influenced by the fact that the pilots' contractual terms relating to pay, hours and holidays were governed by English law. Whether an employee is protected by UK employment law will always depend on the individual circumstances of their employment. It is, however, possible to identify the following checklist of factors which will influence whether UK law applies:
The location of the employing company; Where management, HR functions, training and administration relating to the employee's work take place; Where pay, pensions, tax and National Insurance contributions are payable; The currency in which employees are paid; Whether the employer pays commuting or other related costs; The amount of time an employee spends in the UK to work, live or to undergo training; Whether legal references in the contract are consistent with the legal system said to be applicable; and Whether there is a clause in the contract dealing with where the parties anticipate legal claims should be raised;
While all these factors will be taken into account, they are not decisive and it is worth noting that the courts will look at the reality of the employment relationship in order to determine whether the connection with the UK is sufficiently strong to merit the protection of UK law. Employers who are thinking of implementing the measures necessary to exclude the applicability of UK law may want to weigh up the cost of this against the risk of potential claims that employees may be able to bring in the UK and any adverse employee relations issues which may arise.
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OilVoice Magazine | MARCH 2013
Super majors feel the pinch in 2012
Written by Eoin Coyne from Evaluate Energy The annual 2012 results of the major players in the global oil and gas industry are out and a distinct picture on how the year has progressed can now be formed. At the top of the food chain, the super majors - consisting of Exxon Mobil, Shell, Total, BP and Chevron - turned out a meagre performance with a 13% drop in earnings for the group as a whole. Of this group, only Exxon Mobil recorded a gain on earnings from the previous year. Trading conditions between 2011 and 2012 have remained very similar. Refining and marketing earnings are slightly higher on the back of higher margins and demand. The oil price, as per the WTI benchmark, has had a relatively steady performance, starting the year at $99, finishing at $92 and experiencing few supply or demand shocks in between. This is in contrast to gas prices that varied greatly in different areas of the world; The average US price fell 25% since last year (now less than $3/mcf) whilst prices for gas in Europe (over $11/mcf) and LNG cargoes to Asia (over $14/mcf) averaged much higher. The diversity in the operations of the major companies safeguarded their earnings from the US and Canadian gas prices to a large extent but the North American independents could do little to keep the situation from hitting their earnings. The impact on Encana and Talisman, two companies who are both strongly weighted towards gas production in North America, was for Encana to report the lowest net income in the company’s history and for Talisman to report its lowest annual income since 1999. The drop in earnings for the super major group can, in addition to the low North American gas realisations, be attributed to a fall in the production rate for the group as a whole. Oil and gas production has now dropped by 3% for the group for two years in a row. The earnings and production performance for the group may paint a slightly bleak picture of 2012 but this only tells one particular side of how 2012 fared for the oil industry. The credit crisis is becoming a more distant memory, the worries of further global economic depression never fully materialised and confidence in the industry is slowly building. This can be seen in total investments for the group, which are 37% higher than 2009 and 2% higher than 2011. All 5 companies in the group strengthened their balance sheets by decreasing net debt by 17% as a whole, with Exxon Mobil and Chevron now able to boast positive net debt positions.
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Net Income ExxonMobil Royal Dutch Shell Chevron Total BP 2011 41.1 30.9 26.9 17.2 25.7 2012 44.9 26.6 26.2 13.8 11.6
Growth 2012 9.3% (14.0%) (2.7%) (19.6%) (54.9%)
The Super majors in Focus Exxon Mobil continued its quiet dominance of their peer group with a 9.3% gain on earnings in 2011. The performance marks the third year in a row of year-on-year income rises for Exxon Mobil since the credit crisis hit the oil industry in 2009. Although the 2012 net income wasn’t enough to surpass the $45 billion that Exxon Mobil made in 2008 before the crisis took hold, the 2012 earnings per share was the largest in the company’s history, due to an extensive share buyback programme. There was little to separate the next two largest publicly traded companies, Royal Dutch Shell and Chevron. The two companies are remarkably similar in market capitalisation, weighting between their upstream and downstream segments and focus of their global operations and their respective net incomes for 2012 followed the same relationship, with reported earnings of $26.6 billion and $26.2 billion for the year. BP’s annus horribilis may have been over 2 years ago in 2010 with the Horizon rig explosion, but 2012 will be another year that the company will be happy to bid farewell to. The year included yet more repercussions from the disaster with further charges of $5 billion and the lower asset base from the large divestiture programme inevitably fed through to the earnings which suffered a 55% drop. Following the disaster and its ramifications, BP is now a very different company to the one it was 3 years ago and with Petrobras now surpassing BP in terms of enterprise value and annual investment, the lines of what constitutes the super major group may have to be redrawn in the near future.
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OilVoice Magazine | MARCH 2013
Insight: Celebrating Angola, celebrating explorers!
Written by David Bamford from Finding Petroleum Sometimes we explorers have a hard time, sometimes we have something to celebrate. So, over my career I have great memories of seeing the first logs from the Machar discovery in the North Sea, from Mars in the Gulf of Mexico, from Foinaven in the West of Shetlands, from Girassol in Angola, from Jubilee in Ghana, and so on. I emphasise that in these examples, sometimes I was ‘on the pitch’, others ‘sitting in the stands’. However, once in a while there are even bigger memory jolts, for example the other day when I saw that BP had announced first oil from Block 31 (the PSVM project) in Angola and that, according to Bob Dudley, BP group CEO, “Over the coming decade, we expect Angola, where we have extensive interests from exploration through to production, to be one of the main hubs delivering growth for BP”.
A view from a helicopter of BP's Plutao, Saturno, Venus and Marte (PSVM) Floating Production, Storage and Offloading (FPSO) vessel. Image owned by BP plc.
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My mind went back to 1995 when due to a kind of ‘domino effect’ of one person leaving the company, I became the leader of a small, fledgling, team attempting to build BP’s business in West Africa, especially Angola although we also had interests in Nigeria (and for a wee while in Mocambique). Within a week or so, I made my first discovery – that there were some determined opponents of our involvement in Angola, folk who saw risk not opportunity, who thought that the 3rd world, and Africa in particular, was a scary sort of place (in comparison with say the Gulf of Mexico, Alaska, the North Sea), and who tried very hard to get us to stop. I could never figure out whether this was xenophobia or maybe neophobia, or just intra-executive rivalry. You know who you are – for other interested parties, names will be supplied by e-mail! But my second discovery was that there were many supporters – John Browne, Rodney Chase, Chris Wright, Tony Hayward, Ian Vann - who made sure that we continued and had the resources that we needed, could call on support in Luanda (and Lagos) whenever we needed it, and so on. And finally I discovered that my small team had some great explorers in it – folk who became ‘legends’ in the company! You also know who you are! So we rolled forward through 1996, 1997 and into 1998, making discoveries in Block 17 and 15, appraising them, enjoying Shell’s failures in Block 16 (it is a competition after all!), encouraging the Angolan Ministry of Petroleum and Sonangol to offer new ultra deep water blocks, working with our partners (Elf and Exxon), culminating in a scary (for me!) few weeks early in 1998 when first of all I had to show up at the BP Group Chief Executive’s Committee with a $1bn+ Finance Memorandum for the FPSO-based development of Girassol followed by something almost as large for our access to the ultra deep water blocks, especially Block 31. Block 31 was awarded in May 1999 and BP now has interests in nine offshore Angola blocks (15, 17, 18, 19, 20, 24, 25, 26 and 31) with operatorship of four (18, 19, 24 and 31) and participation in Angola LNG. Quite a story! And of course I’m proud to have had a small part in it. But this article isn’t a display of hubris, or at least I hope not. My point is that exploration is highly creative, in some ways the true research activity of an oil & gas company, and oftentimes faces strong opposition, for example from engineers and accountants, who are given to saying things like “I don’t see the value proposition here!” to which the only response is “Yes, you don’t see it….but it’s there!” Thus a piece of Bob Dudley’s comment that I especially enjoyed was “PSVM is one of the largest subsea developments in the world and was one of BP’s key project start-ups for 2012 as we grow higher-margin production.” So fellow explorers, I will offer you my following modification of a saying attributed sometimes to Sun Tzu, sometimes to anonymous Japanese sources: "If you sit by the river long enough, you will see (the bodies of) your opponents float by.”
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Finally, I must pay a tribute to a true unsung hero of BP’s involvement in Angola, namely Dick Field, who for at least a decade was our ‘man In Luanda’ enduring bouts of malaria, the civil war, numerous disappointments, all the time building the relationships which delivered in the end.
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E & P in Libya following the revolution
Written by Matt Luheshi from Finding Petroleum The oil industry in Libya is now over 55 years old. It has a complex history starting in the days of the kingdom (1951 – 1969) and developed further under the Gaddafi regime (1969 – 2011). A simplistic but not unfair characterisation is that Libya has great world class potential that has been poorly resourced and developed – not through lack of dedication of the professionals in the industry but through neglect and mismanagement at a political level by the previous regime. Libya is a good example of the impact of politics on exploration history. The pace of exploration and exploitation show a clear imprint of the political environment created by the behaviour of the Gaddafi regime. This has very important consequences on perceptions of the stage of maturity exploration of Libya’s various basins. In spite of the recent renewal of exploration in Libya (since lifting of UN sanctions in 2003) Libya’s oil industry is still arguably immature.
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Exploration history Libya has a diverse and very rich set of working hydrocarbon basins, supported by distinctive geographic advantages. The discovered resource is ~60 bnboe (recoverable), of which ~50% has been produced to date. The ultimate resource is almost certainly very much higher than this figure (a figure of ~100 bnboe is not unreasonable – that Libya’s exploration is immature is a commonly held view). Current production capacity is ~1.6-1.8 mboed.
There is a complex legacy that needs to be managed. The elements are well known and include oil fields and infrastructure that are in decline. There is also a major exploration potential that is not being exploited as effectively as modern science allows. There are commercial agreements in place with diverse terms and with a wide spectrum of operators. The Libyan Revolution of 2011 was a tumultuous and momentous period for the country that has opened up great opportunities on the political, social and economic fronts. What could be the impact on the oil industry looking forward? This is the third major dramatic change in Libya’s political situation (creation of the Kingdom in 1951, Gaddafi’s military coup in 1969 and the popular revolution of 2011). Aspirations to create a democratic government will inevitably have an impact on how business gets done in Libya. The pressure for modernisation is powerful and is likely to lead to a more accommodative and cooperative governance structure for the industry in Libya. This paper discusses the opportunities and risks facing the country and its international oil industry partners. The opportunities are still world class. While the risks are numerous the new political context sets a positive environment and the emerging trends are pointing to establishment of a much more modern business
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orientated oil industry in the country. This will take time to establish and patience will be needed. Since the election of a democratic General National Congress in July 2012, a clear timetable has been laid out to develop a new constitution and national institutions. Whilst progress is being made, the many political tensions in the country and continuing difficult security situation have inevitably introduced delays. Recently a process for electing a constitutional assembly was announced. This assembly will be elected through a national vote. It is likely that the drafting of a new constitution will stretch into 2014. This will finally establish the governance framework of New Libya and the management of the oil and gas resource will be a major element. In the meantime existing oil and gas agreements will continue to operate; with any adjustments that are needed being made at an administrative level. The scale of the remaining hydrocarbon opportunity in Libya is world class. The effectiveness and efficiency of future exploitation of this resource depends critically on the new legal framework and executive institutions that Libya chooses to create. The technical risks and uncertainties are amenable to application of modern science and technology. There are no particular exceptional petro-technical risks. The country also has a clear and obvious geographic advantage. This, together with the general high quality of Libya’s crude, makes this opportunity technically very attractive indeed. The main issue looking forward surrounds political risks. Libya’s geo-political importance relative to Europe is such that a very large amount of international support is being deployed to help see the country safely through this transition. Given the generous support from the UN, regional governments and international NGOs, it is highly likely that the processes in place to deliver a new constitutional framework will play out in a positive way. Today the complex internal and regional dynamics express themselves as political risk and uncertainty. A number of scenarios for the future political state of the country are possible. The emergence of a constitutional democracy is probably the most likely. The shape of this is unclear given the difficult internal environment, but the general popular will is driving towards a democratic outcome. The potential for Libya to finally become one of the best oil and gas producers in the world is real. Some patience will be needed while the political dynamics play out.
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Finding big oil elds in East Africa ..onshore, yes, but are there any o shore?! London, 09 Apr 2013 Finding big oil & gas elds in South East Asia The Politics may overwhelm the Geoscience! London, 14 May 2013 Delivering well integrity How best to manage well integrity - errant technologies, new technologies? London, 22 May 2013 Developments with FPSO operations Better ways to make decisions about specifying and operating FPSOs London, 04 Jun 2013 Russia & the FSU - plenty of opportunities below ground, plenty of problems above ground! London, 18 Jun 2013 Exploiting deep water elds ....it's not as easy as explorers think! London, 19 Sep 2013 Exploring internationally for unconventional oil and gas ....... nding the "sweet spots" London, 02 Oct 2013
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An unexpected surge in U.S. condensate production: From Eagle Ford to Canada
Written by Keith Schaefer from Oil & Gas Investments Bulletin Investing in Condensate, Part I explained what this hot new commodity is; Part II outlined the bullish case for Canadian condensate demand, and in this third and final article on condensate, I review American efforts to move their glut of condensate north. Condensate is making uneconomic gas wells profitable for producers in the shale basins of northern BC and Alberta, and creating some great investment opportunities for informed investors. The reason condensate is king in Canada is that oil sands producers need piles of this light oil to dilute their heavy bitumen for transport, and Canadian production can’t keep up with demand. How long can this party last? Shale oil and gas basins in the United States are churning outcondensate, where demand is very limited. A glut is developing. That glut is needed up north, so infrastructure players are busy planning, permitting, and building pipelines to move America’s piles of condensate to the Canadian oil sands producers that need it. Once that happens, will condensate’s Canadian price premium evaporate? It’s an important question, as strong condensate prices are the only leg many Canadian gas producers have to stand on right now. America’s Unexpected Condensate Wealth The Shale Revolution has transformed America’s energy scene. After decades of decline, US oil production is again on the rise. The turnaround has been even more dramatic on the natural gas front: shale wealth has transformed the country from an importer to an exporter and pushed prices to historic lows. Condensate production is an unexpected sideshow of the shale phenomenon – but it is starting to steal some of the limelight because shale wells are producing just so much of it.
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OilVoice Magazine | MARCH 2013
Take the Eagle Ford shale basin, which stretches across much of south and east Texas. The basin’s tight sedimentary rocks contain a range of hydrocarbons: wells on the southeastern flank generally produce dry gas, wells in the middle produce gas, natural gas liquids (NGLs), and condensate, and wells to the northwest generate oil and condensate.Eagle Ford producers drilled their wells looking for oil or gas. Condensate was an unexpected bonus – but it now makes up as much as 40% of the hydrocarbons produced from the formation. Forecasters predict that total Eagle Ford oil output will reach 500,000 to 800,000 barrels per day (bpd) by 2020. A large number of those barrels – somewhere between 250,000 and 400,000 bpd – will be condensate. Compare that to 2011, when condensate production from the formation averaged 130,000 barrels per day. It means condensate production from Eagle Ford will likely grow by 150% in less than a decade. And Eagle Ford is just one of a slew of shale basins being drilled and fracked apace in the United States to produce oil, natural gas, NGLs, and condensate. It sounds great, right? Not only are shale basins producing the natural gas and crude oil expected, they are also churning out piles of condensate, a hydrocarbon mixture so light you could often pour it straight into your tractor. Condensate must be making US shale producers happy, right? Wrong. Condensate and US Refineries – A Poor Match Since it is produced alongside oil and since it is in fact oil, producers lump condensate with oil when reporting production volumes. As a result, it seems like US oil production is shooting through the roof. But while domestic output is certainly rising, lumping condensate in with crude is misleading because not every hydrocarbon molecule is created equal – especially through the eyes of a refinery. Half of America’s refineries lie along the Gulf Coast. With the ability to process 8 million barrels of crude oil every day, this industrial complex truly sets the tone for oil pricing across the country. And guess what? Gulf Coast refineries don’t like condensate. What Is This “Freak of Nature” Gas Play? In short, it has the best economics of any pure gas play I’ve ever seen in my life. And in this new briefing, I take you through, point by point, why I think this one natural gas stock, a pure play on gas, could be the single best trade in the sector – junior, intermediate or senior. Keep reading here to learn more…
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OilVoice Magazine | MARCH 2013
Refineries are picky beasts, each one only able to process crudes within a particular API range. The Gulf Coast army of refineries used to love light oil, but over the last 25 years the world burned through many of its high-quality deposits of light crude. That forced producers to shift towards heavier and sourer crudes. In response, US refineries invested billions in upgrades to be able to process these more complicated crudes. In fact, from 2005 to 2009 the US refining industry spent $47.6 billion on heavy oil upgrades. Then came the Shale Revolution. Fracking technology is the engine for America’s drive for increased energy independence. Suddenly producers were pumping good quality oil from shale basins across the continent.The refineries can handle shale oil. They cannot, however, handle muchcondensate. The only way to feed condensate into these medium and heavy oil refineries is to mix the light oilwith a heavier crude, to produce a mid-weight blend. But even that is not ideal, because it turns out a mixture of heavy oil and condensate does not produce the same products as a straight crude of similar weight. Specifically, a mixture of light condensate and heavy crude produces lots of very light products, such as naphtha, and little to none of the heavier and more valuable distillates used to make diesel and jet fuel. So, since a crude-condensate blend produces less valuable products than a straight crude of the same average weight, refiners discount the price they’re willing to pay for blends. The unexpected surge in condensate production has collided head-on with low demand from US refineries, resulting in poor pricing. In general, Gulf Coast crude marketers have been paying about $15 per barrel less for condensate than for the light crude it is produced alongside. Since it is cheaper than crude, refineries are buying some condensate and mixing it with heavier crudes for processing. The products are worth less but input costs are also lower, so it works out ok for refiners’ bottom lines. It does not, however, work out well for producers. Shale producers invest millions of dollars into each multi-stage frac well. They don’t want to sell half their production at a discount – they want buyers who are willing to pay top dollar for all this light, sweet condensate. Those buyers, as we learned last week, are north of the 49th parallel. Getting Condensate to Canada Canada needs condensate. US producers are flooded with the stuff and want to sell it to Canadian oil sands operators. The challenge is moving it. The only pipeline currently moving condensate from the US into Canada is Enbridge’s Southern Lights line, which runs from Illinois to Edmonton. It can move
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180,000 barrels per day, which can more than handle the 110,000 bpd of condensate being imported now and Enbridge is proposing an expansion.
The hard part, the bottleneck, is getting it to Patoka, where it can enter Southern Lights. Patoka, it turns out, is not particularly close to the biggest condensateproducing shale in the US, which is the Eagle Ford basin in Texas. There are ways. For example, Plains All American is using the Louisiana port of St James as a staging post to route Eagle Ford condensate into the Capline pipeline for shipment to Patoka. Others are using existing gathering networks to move condensate to Corpus Christi on the Texas Gulf Coast, where it is loaded onto barges and transported to St James. Magellan Midstream Partners and Copano Energy are taking this one step further, extending one of Copano’s pipes by 140 miles to Corpus Christi. That line should soon be moving 100,000 barrels of condensate a day. KINDER MORGAN’S PLANS Kinder Morgan is also working to establish itself as an Eagle Ford condensate shipper. Kinder is building a condensate pipeline that can move 300,000 bpd from the shale basin to the Houston area, which is already being used to capacity.From Houston, the condensate from Kinder’s line moves through the company’s Explorer pipeline to Hammond, Illinois. That’s progress, but Canada is still hundreds of kilometers away. To connect its system to Canada, Kinder has two plans: 1. Extend Explorer to connect with Enbridge’s Southern Lights—one ends and another starts in Illinois. That link should be in service by early 2014.
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2. The other is to connect Explorer to the Cochin pipeline. Cochin moves propane 1,900 miles west to east—from Alberta to Ontario—through the US, crossing the border in North Dakota and skirting south of the Great Lakes before re-entering Canada in Windsor. Propane volumes have been declining, so Kinder is proposing to reverse and expand part of Cochin—from east to west—to move 95,000 bpd of condensate from Illinois to Alberta. Industry support for the project is clear: when Kinder held an open season on its Cochin proposal, the company received binding commitments for 105% of the proposed capacity. US regulators approved the plan in October; Kinder is now awaiting word from Canadian regulators. If all goes according to plan, the reversed Cochin will start moving condensate from the Midwest into Canada by mid-2014. Plans from Kinder and Plains All American alone will increase Eagle Ford condensate capacity to Alberta by 170,000 bpd by the middle of 2014. Other pipeline projects are also in the works. Not willing to wait, some US producers moving their condensate to Canada by rail. The upgrades are coming, and all signs indicate that every condensate pipe in the works will be filled to the brim almost from day one. Even without much dedicated infrastructure, condensate sales from the US to Canada have skyrocketed in recent years. Every estimate is different, but some analysts estimate that US condensate exports to Canada have grown 1,000% in the last two years alone. CONCLUSION Condensate capacity from the US to Canada should increase dramatically—but it is over a year away. Oil and gas marketers in Alberta tell me oilsands production is rising fast enough to use a lot more condensate—but only time will tell if the market stays in balance, over-supplied, or under-supplied. There’s a lot riding on this equation for Canadian natural gas producers—strong condensate pricing is the only thing between a lot of them and bankruptcy.
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