OilVoice Magazine | August 2014

Edition Twenty Nine – August 2014

Kurdistan: the newest oil producer?

What if oil companies applied cybersecurity tactics to safety?

Marginal field development in the UKCS using innovative low cost solutions Cover image by shannonpatrick17

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OilVoice Magazine | AUGUST 2014

Adam Marmaras Chief Executive Officer Issue 29 – August 2014 OilVoice Acorn House 381 Midsummer Blvd Milton Keynes MK9 3HP Tel: +44 208 123 2237 Email: press@oilvoice.com Skype: oilvoicetalk Editor James Allen Email: james@oilvoice.com Director of Sales Mark Phillips Email: sales@oilvoice.com Chief Executive Officer Adam Marmaras Email: adam@oilvoice.com Social Network

Welcome to the 29th edition of the OilVoice Magazine.

The OilVoice Jobs Board continues to experience month-on-month growth.

So, if you’re looking to kick start a career in the Oil & Gas industry, make sure you upload your CV to your OilVoice account.

This month we have great articles from Oil & Gas Investments Bulletin, ABT Oil & Gas and RMRI, and Mars Omega. We'd also like to welcome back some of our regular authors, including Andrew McKillop and Mark Young.

If you're interested to know more about seeing your articles featured on OilVoice, please get in touch.

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Contents

Featured Authors Bios of this months featured authors

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Marginal field development in the UKCS using innovative low cost solutions

by Chidozie Ewuzie & James Fox

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How will independence affect the oil and gas industry in the North Sea?

by Matthew Foster

11

Kurdistan: the newest oil producer?

by Anthony Franks OBE

12

TX/ND/PA: The U.S. axis of energy independence

by David Blackmon

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Oil path signals wrong way for world energy

by Andrew McKillop

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Are oil and gas companies capable?

by David Bamford

24

The rise of Saudi TexKota

by David Blackmon

27

Reality blows oil seriously off course

by Andrew McKillop

29

The debt double standard for Canadian vs American energy producers

by Keith Schaefer

32

What if oil companies applied cybersecurity tactics to safety?

by Loren Steffy

37

Oil & Gas M&A in upstream sector reaches $51.3 billion in Q2 2014

by Mark Young

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Featured Authors Chidozie Ewuzie & James Fox ABT Oil & Gas and RMRI ABT Oil and Gas (ABTOG) is creating a new marginal field sector within the oil and gas upstream market: the economic development of small or stranded hydrocarbon accumulations.

RMRI is an independent, risk management consultancy delivering bespoke decision making support for over 20 years.

Mark Young Evaluate Energy Mark Young is an analyst at Evaluate Energy.

Keith Schaefer Oil & Gas Investments Bulletin Keith Schaefer is the editor and publisher of the Oil & Gas Investments Bulletin.

Anthony Franks OBE Mars Omega LLP Anthony is responsible for managing and controlling the extensive information networks, as well as directing and working with the analysis team to create reports for clients, and also works with Hamish in the Liaison and Mediation service.

David Blackmon FTI Consulting, Inc. David Blackmon is managing director of Strategic Communications for FTI Consulting, based in Houston.

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Loren Steffy 30 Point Strategies A senior writer for 30 Point Strategies and a writer-at-large for Texas Monthly.

Loren worked in daily journalism for 26 years, most recently as an awardwinning business columnist for the Houston Chronicle, and before that, as a senior writer at Bloomberg News.

Matthew Foster Strategic Resources Matthew Foster is a recruitment consultant at Strategic Resources.

David Bamford Petromall David Bamford is a past head of exploration and head of geophysics at BP, and a founder shareholder of Finding Petroleum.

Andrew McKillop AMK CONSULT Andrew MacKillop is an energy and natural resource sector professional with over 30 years’ experience in more than 12 countries.

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Marginal field development in the UKCS using innovative low cost solutions Written by Chidozie Ewuzie & James Fox from ABT Oil & Gas and RMRI Forty years ago the United Kingdom Continental Shelf (UKCS) boasted a small number of very large oilfields discovered by major operators. Now, as a mature offshore basin, the average discovery size has shrunk to a fraction of what it once was with small and medium independent companies dominating the region. Oil and Gas UK estimate that 42 billion barrels of oil equivalent (boe) have already been produced from the UKCS and a further 12 to 21 billion boe could yet be recovered 1.

Many studies show that these resources are likely to be increasingly smaller accumulations which are technically challenging and economically marginal 2. In recent years, the UKCS has also consistently recorded one of the highest levels of unit capital and operating expenditure of any oil producing region in the world 3.

These conditions combine to ensure that many small fields are not developed due to marginal economics.

Despite the meteoric rise in development costs in the last few years to the point where the unit costs of development and operation are now approaching ÂŁ30 per boe 4, two new production systems have been introduced to the market that enables such fields with marginal economics to be developed. They cost a fraction of traditional production systems and can be Normally Unattended Installations (NUIs).

The huge reduction in capital costs at the front end of the project and the savings in operating expenditure along the production period combine to drastically alter the project economics. For example, a development project involving three small fields with combined gross reserves of 30 million boe using one of the systems was modelled and the results showed it delivered a post-tax profit of over half a billion pounds.

A review of the UK offshore oil and gas recovery and its regulation was commissioned in 2013 by the Secretary of State for Energy and Climate Change, the Rt Hon Ed Davy MP. The UKCS Maximising Recovery Review was led by Sir Ian Wood who issued his final report earlier this year in which he called for a new strategy for Maximising Economic Recovery ('MER') in order to reverse some of the trends evident in recent years, notably: 

Declining production: Production has fallen by around 38% over the last 3 years producing around 500 million boe less over the period 5.

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





Rising costs: The UKCS is now one of the most expensive offshore regions in the world with development costs per barrel having risen five fold over the last decade 6.

Ageing assets: Some operating assets are over 30 years old, beyond their design life 7. As production continues to decline, maintaining these assets will become unsustainable.

Low exploration drilling: Only 15 exploration wells 8 were completed last year and just 79 million boe of recoverable reserves were discovered in the UK 9. The last three years have witnessed the lowest rate of exploration activity in the history of the UKCS 10.

These issues are longstanding and unlikely to be completely resolved in the near future. A pragmatic approach is therefore required to stem the decline in production.

The Wood Review highlighted the need for better use of existing infrastructure but also recognised the need for applying low cost, standalone solutions to small field development that do not rely solely on channelling production through ageing assets.

The number of marginal fields in a geographic region slowly increases over time and the field size distribution typically follows a lognormal distribution. As larger discoveries are developed initially, much like in the North Sea, this leaves a scattering of smaller accumulations spread over a vast area. As this area continues to mature and decommissioning activities increase due to cost and age, access to these smaller accumulations become more difficult, and they become further removed from existing infrastructure.

The opportunity The scope of marginal fields and their potential in providing a much needed boost to production and revenues for mature basins such as the UKCS which has been the subject of a great deal of discussion in recent months. There are an increasing number of marginal fields in the North Sea with the average size of new discoveries now less than 25 million boe and declining. Given that a majority of the discoveries in the future are expected to be relatively small, bringing them into production is critical to maximising economic recovery for the UK. Therefore, we believe that having a marginal field development blueprint is essential in order to achieve the goals of MER UK as described in the Wood Review.

Marginal fields can be broadly classed as fields with any of the following five characteristics: 1. Low stock tank oil initially in place (STOIIP) and therefore low recoverable reserves.

2. Long distance from existing production facilities thereby making the field economically unviable to develop and put on stream.

3. Fields not yet considered for development because of marginal economics under the current market and fiscal conditions.

4. Fields with technically challenging crude oil characteristics (such as crude with very high viscosity and low API gravity) which cannot be produced through conventional methods or would require significantly increased capital investment to develop.

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5. Low volume producing fields which have become uneconomic due to production income falling below operating expenditure.

Excluding medium to large fields with challenging technical characteristics which require significant capital investment to overcome, such as the Mariner field located in the northern North Sea, and end of life fields, the majority of marginal fields are small discoveries. These discoveries are generally determined towards the end of a project lifecycle. Leads and prospects may have huge estimated resources at the initial stage but they are gradually pared down by seismic assessment and other techniques such as exploration and appraisal drilling. When discoveries are determined to have small reserves and classed as marginal, operators are then faced with tough decisions such as a part or full asset sale or holding the asset in their portfolio with no imminent decision on development. These small fields cannot support the cost of traditional exploration and extraction methods typically employed in the North Sea over the last 40 years.

Fixed steel structures are not viable solutions for marginal fields due to their enormous cost outlay and need for many years of production which goes beyond the much shorter production period for marginal fields. FPSO's are usually not considered for marginal fields as the lower production rate mean revenue generated is unable to sustain the daily lease rate and operational cost. While tiebacks to existing infrastructure may be an option for some marginal fields, commercial and technical complexities can prove to be challenging and have often held back such development options. For fields isolated from existing production systems, tiebacks are not an option. Due to cost constraints, the average tieback distance for small fields is approximately 10 km 11. A low cost solution is needed if the goal of marginal field development is to be achieved and therefore, capital and operational expenditure has to be reduced.

The solution The Wood Review states that new technology will be key to enabling the exploitation of new and complex discoveries which are generally smaller and often remote. Given that new technology will likely take years of testing and intense scrutiny before gaining industry acceptance, existing and proven technology solutions are needed to deliver immediate results.

Recognising marginal fields as a huge untapped resource, British company, ABT Oil and Gas (ABTOG) scoured the market for proven technology which could be adapted to transform the economics of small or stranded reserves. Having identified appropriate solutions ABTOG, along with its partners, have developed two production systems, the Production Buoy and the Self-Installing Floating Tower (SIFT), which fit the strategic objectives of their marginal field initiative. They are relatively low cost systems which combine existing and proven technologies reconfigured to deliver innovative solutions for marginal field development. They are generically buoyant solutions for use in offshore oilfields with an operating envelope of water depth up to 600m and liquid production rates of up to 20,000 barrels of oil per day.

Both systems can be remotely operated Normally Unattended Installations (NUIs)

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incurring relatively low operating costs thereby providing significant cost savings compared to more conventional production systems such as FPSOs. The SIFT is simple to fabricate and transport, as evidenced by the CX-15 Buoyant Tower which uses similar existing and proven shallow water technologies. The CX-15 is currently installed in the Corvina field offshore Peru and took 13 months to design, build, transport and install. The Production Buoy and SIFT are ideally suited for developing fields in mature basins such as the North Sea which have an increasing number of small fields and can also be redeployed to new fields, significantly reducing the capital expenditure required to bring a new field on stream. Working with strategic partners these production systems have been designed for use in the North Sea and are also well suited for regions of seismic activity.

The benefits To demonstrate the benefits of ABTOG's solutions, a discounted cashflow model was developed to illustrate the development of three identical marginal oilfields with 10 million boe reserve size each and a production life of 6 years using a single SIFT. Since the SIFT units are able to be redeployed, the model starts with a single field producing for 6 years and at the end of production, an 18 month break to retrofit the SIFT is taken and a second field is subsequently developed using the same SIFT. This process is repeated for the third field and eventually, close to 30 million boe is produced over a 21 year period.

With oil prices fixed at $90 per barrel, the project generates revenue of £1.7 billion based on an estimate capital and operating expenditure of over £660 million. The project generates a pre-tax profit of just over £1 billion. With £485 million deducted as corporation tax on production for the Treasury, even after deductions for the small field tax allowance, this gives a post-tax profit of £555 million. This equates to £18.50 of post-tax profit per boe and £16.20 of tax income per boe.

The total recoverable for discovered undeveloped marginal fields in the UKCS is estimated as 1.2 billion boe. If we assume that all the marginal fields are developed and the total reserves produced, then the potential post-tax profit based on a $90 per barrel oil price is £22.2 billion for operators and the potential tax income to the Treasury is £19.4 billion. Given that the recent production decline is estimated to have cost the Treasury over £6 billion in lower tax receipts 12, this will contribute to make up for the shortfall and also give the national economy a much needed boost.

UK energy security will be significantly strengthened and there will be benefits for the Treasury as the spending on oil imports which runs into several billion pounds annually is reduced. As such, the balance of payments deficit will be reduced.

According to the Office for National Statistics (ONS), the balance of trade in crude oil was in deficit by around £9.8 billion in 2013. If these fields are put on stream, added revenue will ensure this deficit is eroded and benefit the Treasury in the form of tax revenue.

Also, it is estimated that developing these marginal fields will lead to a potential investment of over £26 billion in capital and operating expenditure and this could in turn lead to the creation of over 2,500 new jobs in the UK and support many thousand more along the supply chain and the contribution to the local economy could be substantial. These results show that the size of the opportunity and the

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potential returns to operators and contribution to the Treasury are very significant.

In addition to the benefits for the producers and the Treasury, marginal field development offers a major new area of commercial opportunity for the UK's oil and gas supply chain industry which could benefit by building expertise in marginal field technologies, with the potential to transfer these to other mature offshore basins.

The Production Buoy and SIFT could be further developed to enhance efficiency and performance, and is able to be adapted to the characteristics of other offshore regions. Indeed, although the UKCS is one of the most mature hydrocarbon basins, the need to develop marginal fields does not apply to the North Sea alone. Our analysis shows that marginal fields of sufficient size and water depth are located across the globe in nearly every offshore jurisdiction, opening up a massive global market for these systems. These low cost solutions can also be applied to brownfields being redeveloped, clusters of marginal fields or isolated small fields, unlocking billions of barrels of oil and gas reserves with significant potential.

The Conclusion There has not been a significant (multi-hundred million boe) discovery for five years in the UKCS 13 and it is uncertain if any will emerge in the future. Mature petroleum regions such as the UKCS will therefore become increasingly reliant on the development of smaller, marginal hydrocarbon reserves which will struggle to be exploited using relatively high cost conventional production systems. As such, a huge market with unforeseen potential exists which can be unlocked by applying proven, innovative production systems to achieve significant cost savings and early production delivery. ABTOG is at the forefront of these developments with access to technologies, systems and a business model ideally suited to marginal field opportunities.

Thanks to ABT Oil & Gas (http://www.abtoilandgas.com/) and RMRI (http://www.rmri.co.uk/) 1

UKCS Maximising Recovery Review: Final report J. Harpin (2011). Measuring the impact of aging infrastructure in the UK North Sea 3 See reference 1 4 Oil and Gas UK Economic Report 2013 5 ibid 6 ibid 7 ibid 8 https://www.gov.uk/oil-and-gas-wells#drilling-activity 9 Wood Mackenzie – Review of 2012 & 2013 – UK upstream sector 10 Oil and Gas UK Activity Survey 2014 11 See reference 2 12 See reference 10 13 Wood Mackenzie industry database 2

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OilVoice Magazine | AUGUST 2014

How will independence affect the oil and gas industry in the North Sea? Written by Matthew Foster from Strategic Resources With Scottish referendum fast approaching, how will independence affect the Oil and Gas industry in the North Sea? It's a question many of the companies based in Scotland have been thinking or even asking the Scottish Government. In one hand it might be seen as step forward moving away from constraints of the UK Government, or in the other hand, it could be seen as a backward step with oil companies losing UK agreements already in place. However, a fundamental question is how much does an independent Scotland rely on Oil and Gas? It is seen that an independent Scotland will need significant revenues to increase their budget responsibilities and Oil and Gas industry is, and always will be, Scotland's main revenue, but of course this is seen as 'fantastical' and is based on unrealistic oil forecasts according to the Chief Secretary to the Treasury. Also, with oil production decreasing in the North Sea and oil revenues at all time low in 2013, Professor Sir Donald Mackey calls this a 'mountain of black gold' so how can the Scottish Government truly believe that oil revenues totalling between ÂŁ2.9bn and ÂŁ7.8bn in 2016-17 be realistic if Scotland becomes independent. Obviously, North Sea production will always be there for decades to come, but shouldn't the 'yes' campaign be clearer with their voters on this issue and not just say numbers and figures to wow us all? We must have facts on revenues and we must hear these facts from both parties and from companies in the industry itself.

Also, we need to look at the oil and gas companies and their views on Independence; what affect will it have on them? Sir Ian Wood and his report on the oil and gas industry provided a great insight to the affects of Scottish Independence with other facts. Sir Ian Wood stated, 'We need clarity over the coming years so that our clients will understand the environment they'll be working in, if independence is the outcome of referendum'. Of course we, 'the voters', need clarity on the environment after independence as thousands of Oil and Gas workers onshore and offshore will need to know how an independent Scotland will affect them.

Furthermore, the workers in this industry provide the taxes and growth for the Scottish economy and the Scottish Government need to tell the companies and workers their plans.

Lastly, what happens if oil and gas companies want to move operations from Scotland to England and in turn support both Scotland and England, revenues would surely decrease or be split. For example Royal Bank of Scotland (RBS) stated that if

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there is a 'yes' vote RBS could leave Scotland and set up operations in England.

Also, if a company as large as RBS is thinking of leaving Scotland what would stop companies within the Oil & Gas industry taking the same path with 1/3 wanting to see Scotland remain part of the UK? I believe this is the most alarming part of the 'yes' vote as citizens/voters of Scotland could possibly lose jobs.

Whatever the vote is on 18th September 2014, Scotland's future will definitely be changed either for the good or the bad. Obviously, there needs to be information and clarification given to the voter from both parties on how revenues from the Oil and Gas industry will support the Scottish economy. Also, major development within the Oil and Gas market will need to take place in order to maximise production and bring in the possible revenues which have been quoted by the Scottish Government.

Obviously the companies in Oil and Gas industry will need to hear answers to their questions so that they know how independence will affect them. Let's hope whatever the vote is that Scotland can become better at what we are good at.

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Kurdistan: the newest oil producer?

Written by Anthony Franks OBE from Mars Omega LLP The world might be on the cusp of seeing a new oil producer: Kurdistan.

According to a Bloomberg report, in the last 48 hours Deutsche Bank AG said that Kurdistan oil is “poised to gain acceptance” following the apparently successful sale of an initial cargo of oil for $93M. According to Turkish Minister of Energy and Natural Resources Taner Yildiz, four tankers in total have loaded cargoes of Kurdish crude in Ceyhan.

An analyst’s report from Deutsche Bank AG said “We expect trading houses to become increasingly comfortable handling Kurdistan Region of Iraq crude and steady-state exports to emerge.”

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A game changing decision To set this in context, last week a critical ruling by the Iraqi Supreme Court was given in favour of Irbil over Baghdad in the bitter dispute over oil exports. It was also unanimous - suggesting the political grip over the Supreme Court is not as strong as it once was.

In essence, the court refused a request from Minister of Oil Abdul Karim al-Luaibi to issue a temporary injunction against the KRG. The KRG’s website noted that the case was based on the minister’s interpretation of the Constitution claiming that the management of Iraq’s hydrocarbons was exclusively the role of Baghdad.

Irbil further noted, “With this Court decision, the Kurdistan Regional Government has another important clarification of its acquired rights as stated in the Constitution.

Such a decision by the highest court in the land is binding on the Minister and cannot be challenged in any way.”

The statement from the KRG Ministry of Natural Resources (MNR) said SOMO should now stop what they described as “illegal and unconstitutional interventions” to prevent Kurdish oil exports.

The MNR statement also said “They [SOMO] must also cease sending intimidating and threatening letters or making false claims to prospective traders and buyers of oil exported legally by the Kurdistan Regional Government for the benefit of the people of Kurdistan and Iraq,” describing the ruling as “a clear victory for justice and for upholding KRG’s rights.”

However, it is worth noting that the minister’s injunction was rejected on legal grounds; the request by the minister was apparently poorly presented.

The Court did not make an explicit ruling on the constitutional issue, and thus there is an implicit potential for PM al-Maliki to try to secure a ruling on constitutional grounds, as well as allowing the Ministry of Oil a second attempt at an injunction.

Baghdad’s position will also doubtless be that the court’s striking down of the injunction does not explicitly allow the KRG to export oil.

But given the fluid and increasingly acrimonious nature of politics in Iraq, any attempt to resubmit will probably be too little and too late, as the clock ticks onwards.

Unlocking potential What is critical is this decision potentially unlocks the padlock to prosperity and also increases the likelihood of independence for Kurdistan.

Irbil is likely to seek to accelerate Kurdish oil exports. Revenue will then be spent on KRG government salaries and the Peshmerga. This will simultaneously reduce economic pressure on Irbil that Baghdad had deliberately created by withholding the

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KRG’s share of the federal budget, and will also be spent on increasing the military capability of the KRG’s armed forces.

The decision by the Court is also likely to cause a collective sigh of relief across the boardrooms of the IOCs invested in Kurdistan, along with their shareholders and stakeholders.

And even if Baghdad tries to react to the court ruling, there is probably sufficient political momentum created for the KRG to ignore the potential for further legal action by Baghdad.

Furthermore the parliamentary chaos in Baghdad is likely to mean that the focus will be on forming a new government. In a pleasing symmetry, yesterday’s attempt to form a new government in Baghdad degenerated into a farce worthy of Monty Python’s Flying Circus, who opened last night at the O2.

To explain: Yesterday, Parliament convened as required, but after swearing the mandatory oaths, the Kurds and Sunnis in Mutahiddun promptly walked out and made the chamber non-quorate.

The Kurdish MPs marched out after the KRG was somewhat improbably accused by some members of the previously ruling (Shi’a) State of Law party of harbouring members of ISIS, presumably on Kurdish territory.

This inflammatory accusation caused the parliamentary session to implode until 8 Jul 14 when it will reconvene. But unless there is a sea-change in attitudes, there is no guarantee the government will form then, any more than it did yesterday.

The Sunni Mutahiddun MPs appear to have walked out in solidarity with the Kurds, who, along with the Iraq National Alliance, have refused to re-nominate PM al-Maliki as the next PM. Choppy waters ahead However, it is not all plain sailing for the KRG, yet.

In turns of mixed diplomatic messages, over the weekend a leading member of the ruling Turkish AKP suggested that Ankara might be comfortable with an independent Kurdistan.

But yesterday Turkish Deputy Prime Minister Bulent Arinc said “The entire world knows our official view: let Iraq not be split up, let guns not be directed against one another, let people not shed each other’s blood, let outside powers ... pull their hands out of Iraq and let Iraq proceed on its path as an integrated society.”

This is the “official” view. There is doubtless an “unofficial” view.

In the meantime, the Turkish official view seems at first glance therefore to align with Washington, whose spokeswoman Jen Psaki said "At this challenging and grave security, we think it's even more important that all parties - the Shia, the Sunni and

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the Kurds - remain united against the threat they face.�

However, this is somewhat disingenuous: unity is not the issue or question. Some of the deeply divided country is united on an intra-sectarian basis but the lack of political and socio-economic integration is precisely why Iraq is where it is now.

Hence the KRG will see the call for integration and unity as something that can be officially considered.

But in the light of President Barzani announcing the intent to hold a referendum in the next few months, ultimately the call for unity could be considered irrelevant if Kurdistan votes that its new national interests trump the geo-political desires and interests of external powers.

The KRG seems to have decided which way the wind is blowing, and has set its sails accordingly.

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OilVoice Magazine | AUGUST 2014

TX/ND/PA: The U.S. axis of energy independence Written by David Blackmon from FTI Consulting, Inc. As we prepare to celebrate our nation’s Declaration of Independence on Friday, it would also be appropriate to take a moment to celebrate those states who are currently leading our nation down the path towards energy independence. No issue facing America today is more important than where we will continue to access sources of abundant and affordable energy.

Energy heats and cools our homes and office buildings, fuels the automobiles that get us to work, facilitates the growing and transport of the food that sustains us, serves as the feed stock for thousands of products that make our daily lives more convenient and raise our standard of living. It is literally the life blood of our economy, and has been for more than 150 years.

For too many years, our country has found itself dependent on oil imported from other nations, many of whom are hostile to U.S. goals and ideals. As we move into the future, our increasing independence from these foreign supplies of oil is key to enhancing our national security and affording our leaders geopolitical advantages that they have not enjoyed for many decades.

In the U.S. today, many states are playing increasing roles in this drive towards energy independence, but three of those states are clearly leading the way: Texas, Pennsylvania and North Dakota.

While Texas has long been known for its extraordinary oil and natural gas production, this week marked a historic achievement for the state’s energy production. According to a new report from the Energy Information Administration (EIA), the Lone Star state is now producing 36 percent of America’s oil – rivaling some of OPEC’s largest oil suppliers. From the EIA: “Texas production topped 3.0 million bbl/d for the first time since the late 1970s, more than doubling production in the past three years, and North Dakota production broke 1.0 million bbl/d for the first time in history, nearly tripling its production over the same period… Gains in Texas crude oil production come primarily from counties that contain unconventional tight oil and shale reservoirs in the Eagle Ford Shale in the Western Gulf Basin, where drilling has increasingly targeted oil-rich areas, and multiple reservoirs within the Permian Basin in West Texas that have seen a significant increase in horizontal, oil-directed drilling.”

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Thanks to this tremendous production from Texas oil plays, the state is now toe to toe in production levels with Iraq, one of OPEC largest oil producers. As the Houston Chronicle describes: “Nearly as much crude flowed from Texas as from Iraq, which was the second largest OPEC producer in April at 3.2 million barrels per day, according to estimates from Bloomberg . The news agency estimates that Iraq’s production fell to 2.9 million barrels in June amid insurgent violence, which would drop it below Texas oil if the state’s supply continued to rise as it did every month since 2011.”

As Texas leads the United States and the globe in energy production, states outside of Texas are also experiencing tremendous growth. In North Dakota, oil production has tripled in the last three years while the state experiences record low unemployment levels, and the nation’s fastest-growing state economy. Indeed, when combined together, Texas and North Dakota now produce almost half of all the oil produced in the U.S. Given that overall U.S. oil production has increased by 50% since 2006, that is an amazing accomplishment for these two states and the state policymakers who have played such important roles in making it happen.

Meanwhile, natural gas production continues to soar across the United States, reaching a record of 68.7 billion cubic feet (Bcf) output per day in March 2014. Texas also plays a significant role there, producing almost 30% of all U.S. natural gas from a variety of regions and formations, but the biggest single natural gas field in the country today – the Marcellus Shale – is centered in the state of Pennsylvania. At the end of 2013, the Marcellus field alone accounted for 18% of overall U.S. natural gas production, and that percentage has only increased in the first half of 2014.

While the Marcellus underlies portions of other states, like Ohio, West Virginia and New York, the great preponderance of that production takes place in PA, which is appropriate given that the U.S. oil industry was born in that state more than 150 years ago. The leaders in Pennsylvania should be celebrated this July 4 for persevering to bring all the benefits energy development brings to the people of their state in the face of a withering assault from a vast array of dishonest antidevelopment conflict groups and constant interference by the EPA and other arms of the federal government. Contrast that performance to the utter failure of leadership in neighboring New York, which continues to deny its people the rights to their property and resources for going on six years now, and you see the real magnitude of what Pennsylvania has achieved in the energy realm What Pennsylvania has done doesn’t just benefit Pennsylvanians: it benefits our entire country. The availability of massive new supplies of affordable, stable natural gas has led to a rebirth of all manner of major manufacturing industries that had for decades been shipping their capital investments and jobs overseas. Now, hundreds of thousands of jobs and hundreds of billions in capital investment have returned to this country, as this energy-generated renaissance has basically been the lone bright spot in an otherwise moribund economy.

Get out a map and draw lines from North Dakota down to Texas and then back up to Pennsylvania. If you draw the lines straight, you get a “V” for “Victory”. If you draw them with a curve, you get a big ol’ smiley face. Either way, you get a reason to

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celebrate this 4th of July, as these three great states form the axis that is leading our country towards its Declaration of Energy Independence.

God Bless Texas, North Dakota and Pennsylvania, and God Bless America this July 4.

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Oil path signals wrong way for world energy Written by Andrew McKillop from AMK CONSULT Energy Worlds Apart Recent publication of this year's BP Statistical Review of World Energy illustrates several mega trends in world oil and for energy in general. The Review provides time-series charts where the key change decade of 2003-2013 is covered. These underline how the primacy of oil is threatened. To be sure, wrong way data and false flag trends exist - for example and in particular that China and the US, the world's two biggest economies and two biggest oil importers, now import about a half of the oil they each consume and use.

Their combined total oil consumption now runs at slightly above 27 million barrels/day (Mbd). This is almost exactly 30% of all oil consumed worldwide but apart from that however, China and the US are literally worlds apart in energy despite their converging twin track for imports.

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Among major OECD economies the US is still the largest per-capita oil consumer at around 20 barrels per person a year. China despite its stupendous coal consumption (equivalent in oil terms to about 11.2 barrels per capita per year) - is now an oilintense economy relative to other developing and emerging non-OECD countries.

Relative to the OECD group however, it remains far behind. Despite (or rather because of) its growing oil imports, economic change, and other factors including energy policy China's growth of oil consumption is rapidly slowing. In the OECD group the main metric, almost everywhere, is the rate of decline in per capita and national oil and energy consumption.

While the OECD group is home to about 14% of the world's population but consume around 45% of world oil this particular crossover - the North/South split of world oil demand - has already happened. From 2005-2007 the 30-nation OECD group's oil consumption shrank below that of the emerging and developing South as the South's demand grows - but since 2012 at a slowing pace.

Global and national oil-intensity and energy-intensity trends are able to be calculated from BP's Review, showing that surely for the US and the OECD group declining oil and energy intensity is the major trend and could even be called 'cast in stone'. Much more rapidly than most analysts ever forecast, the same decline trend may also be starting in the emerging economies, especially China.

Commercial and Strategic Security Stocks To be sure, as the chart above shows, US and Chinese oil import crossover is coming. China will soon be a bigger net oil importer than the USA, making China the world's biggest single importer. As of present, their combined total net imports are close to 12.5 Mbd, roughly 24.5% of world net total oil imports but the decline trend

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for US oil consumption, its growing domestic oil production, and China's slowing growth of oil demand all suggest US import decline and Chinese import growth will likely cancel each other out. This suggest no net growth in oil imports by the world's two-biggest importers.

Backing this forecast which itself is bad for oil prices, their combined imports relative to the figure for world total net oil imports - about 51 Mbd - are not strictly comparable. The world net import number is 'fuzzy edged' due to factors as wide ranging as ship and airline oil bunkering, world petrochemicals use (about 4.75 Mbd), world oil refinery gains, oil pipeline transit stocks, and both maritime and land tanker oil in transit. Other factors, on the upstream side include the basic definitions used for 'oil', (eg. NGLs or natural gas liquids), and the reporting of oil trade by different local, regional and international oil trade systems.

The major factor, here, is that net total commercial crude oil imports on a global basis are also very slow growing, like world oil demand, but are also almost certainly over-estimated. Also, commercial crude stocks and oil in transit are matched, and in many OECD country cases exceeded by strategic or national security oil stocks. For the IEA's OECD countries these stocks are mandatory and are reported by the IEA on a regular basis - but in several cases, most dramatically the USA - strategic stocks are massive, needing oil imports to maintain them at high levels. These imports can at any time decline, with a major negative impact on world demand for imported oil, and therefore prices. As we know, both China and India have made the political decision to also constitute and maintain strategic stocks - further raising their apparent need for oil and their import volumes. In the commercial stocks sector, both world shipping and aviation bunkering have grown to massive levels (about 2 billion barrels for ship bunkering, around 7% of world oil demand on a yearly basis).

Decline of these stocks, with slowed growth or decline of shipping activity and more efficient LNG-fueled ships, and clean coal powered and windpower assisted ships, is highly possible or even likely.

Importers, Exporters and Re-exporters Some energy journalist claim they are amazed that, until 1993, China was a net exporter of oil - but the US was for decades a large oil exporter, before becoming a massive but now declining importer. Taking other examples and relative to national oil consumption, we can cite Norway which was a large oil importer, for decades.

The UK was a large net importer, became a short-lived small exporter, and is now poised to again be a net importer - depending on UK refinery trade and other factors (also including bunkering). Countries like Switzerland are very unlikely to ever produce serious amounts of oil, and will remain large oil importers. Countries like Singapore are also large importers, but in this case the city state runs a massive refining industry as well as operating the world's largest shipping hub. Singapore consumes around 190 million barrels a year only for bunkering its shipping hub, but obviously this oil is not consumed in Singapore.

Refinery operations and trade have themselves alone driven a horse and cart through pre-1990's oil metrics and world oil. Basically, world refinery capacity is far ahead of demand, and still increasing at several times the world's tiny annual growth rate for oil consumption, presently around 0.75% a year on average. Despite IEA

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and OPEC claims that 2014 'could see a major recovery of oil demand growth', the yearly trend is also able to contract - anytime the global economy turns down. The 2008-2009 sequence of serial oil demand cuts showed this, but for some major regions - especially Europe - the decline of oil demand is now an 8-year-long trend.

The net result, combined with oil stocks, both commercial and strategis is 'false flag' consumption and demand data for a large number of both unsurprising, and surprising countries. China, for example, exactly like the US, is engaged in a petrostrategy of importing crude and re-exporting value added refined products - a strategy that in the EU28 and Japan has reached the limits of sustainability in economic and financial terms but as yet has not attained its inevitable industrial conclusion - further cutting European oil import demand.

Refining strategy also focuses the world's NOCs or national oil companies, sometimes based on large national oil reserves and production (like several OPEC states) but also including countries with a zero-base of oil reserves or production like Singapore. One interesting effect is that the amount of crude oil in transit or stocked for refining has massively grown in the last 15 years, relative to 'classic' consumption metrics only measuring final consumption. This 'market overhang' is often ignored by oil analysts forecasting oil price changes only using 'classic' metrics.

Not Only Oil BP's Statistical Review, we might have guessed, gives limelight attention to oil but it cannot avoid giving us trend-setting data for world natural gas and coal. Black coal, apart from it still supplying around 67% of all energy consumed in China incorporated in every single 'Low Carbon' cellphone, solar cell and PC exported by China - basically shows the triumph of energy economics. While oil prices remain stubbornly high (after a short flirt with reality in 2008-2009), and gas prices everywhere outside the US remain stubbornly high, coal prices remain stubbornly low. Only because of this, coal demand is increasing, even in 'Low Carbon' climateconscious Europe!

Rates of global coal demand growth far outstrip oil demand growth, and since at latest 2010, world natural gas demand growth. Technology factors like extracting coalbed methane not black coal, and in situ gasification of coal, are likely to further 'bring back coal'. However the plain fact is it never went away. Coal energy's role in world commercial primary energy is now only just behind oil (around 30% for oil and 29% for coal, and about 24% for gas) - signaling another big crossover is coming.

This is energy economics 101 or a return trip to the babyhood of Industrial Civilization but it sets a swirl of sub-trends with potential or probable large impacts on energy prices and trade going forward. In Europe for example, natural gas can't beat coal for power generating - and for Europe that mostly means imported coal, more expensive than local-produced when the financial and taxation overlay is stripped away. Conversely in the US, coal is beaten to a pulp by ultra-cheap domestic natural gas. The only salvation possible for the US coal industry, today, is exporting, notably to Europe in a global coal market that is more than well-supplied.

Going forward, it is hard to see any serious uptick in world coal prices. With cheap coal energy, energy economics say that all other energy prices have to be dragged down, sooner or later. Not bolstered upward.

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Although they only get small coverage in the BP Statistical Review, energy economics is going to seriously affect world, regional and national electric power.

One simple figure can help explain this. In Europe today coal-fired power is growing due to 'brute economics', and the wildly dysfunctional EU28 Emissions Trading Scheme (ETS). Present state of the art ultra-clean coal plants can wrench and convert almost 50% of the chemical energy inside a ton of coal, producing electricity which in some countries - like star player Germany in Europe's energy transition quest - is sold to domestic users at about 25 euro cents a kiloWatthour. This uses imported coal (CIF price including transport for standard energy coal with 8000 kWh per ton) at the princely price of about 1.38 euro cents a kWh on a thermal basis before its 'upgrading' to electricity.

In theory only, this seems like nice business for generators - but not too good for consumer morale and downright bad for electricity demand!

Despite and because of this, and also due to factors including power company corporate lethargy, climate policy blunders and the parasitic antics of the finance industry, however, all of Germany's Big Four power producers like most other generators in Europe continue to emit dire warnings of financial doom, extending to claims they might totally abandon all production of electricity - at least in Germany, unless ETS is reformed. Put another way, electricity like oil has been heavily overpriced, but in the case of electric power the benefits to any major sector of the business or private communities are either low or zero.

Germany's Energiewende transition plan basically only concerns electricity and is based on overpricing it, like its clones in other EU28 countries. Simply because of this energy economics 101, the future of European energy transition is apt to change fast, but under almost any hypothesis we cannot forecast any recovery in German and other European oil demand - and possibly even gas demand. The energy-saving trend is now hard-wired in nearly all developed-OECD countries. Very simply it will first and most affect the most-overpriced forms and types of energy.

Tough Times Coming for Oil Producers BP knows plenty about this but avoids talking about it - it leaves its high price lawyers and the financial press to do the dirty work. Basically there are now nearly as many reasons to not produce oil, as produce it and run the risk of 'unexpected non-performance' in financial, technical, energy economic, environmental and industrial terms. Shell also knows plenty, having unveiled its 'global gas strategy' at the start of the 2000's as a strategic shift away from oil, to gas. Due to unexpectedly high development costs and unexpectedly slow-growing gas prices- - and a rout in US domestic gas prices due to the shale gas boom since 2009 - Shell's Go For Gas strategy is now something of a shambles.

On technical grounds, the so-called 'historic oil majors' have low or small reserve-toproduction bases (years of current production from official proven reserves), and have increasingly high cost oil production profiles - totally unlike a large number of NOCs, not only in OPEC countries. The writing on the wall, here, is for the 'historic majors' to slowly quit the business of extracting and producing oil, and focus other energy and the downstream value-add sector.

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Most international oil majors, and some NOCs have the same problem, but at present and for as long as high oil prices exist they mostly soldier along with uberconventional oil production strategies - but often tapping 'unconventional oil' with all its risks and perils - for example Italy's ENI. Unfortunately for their financial performance, their downstream refining and petrochemicals strategies, supposedly value-adding, have also been weakened by straight overcapacity, and in some cases have started being abandoned due to the ironclad upstream context of ultra-slow global oil demand growth. Quitting the oil business, and even the entire energy business is certainly tossed around in boardroom brainstorming sessions on a regular basis, although it is usually denied.

Reducing this to a single number, oil prices at less than about $70-per-barrel on a lasting basis will trigger a tidal wave of pent-up financial and industrial change in the world oil patch. BP's Review skates away from showing us charts and data on worldwide true-basis oil production costs, but the oil industry now needs high or very high oil prices on a historic basis, simply to survive. As already mentioned, oil energy is uber-expensive compared with coal, (and compared with gas energy in the US), meaning that for example oil's share of world energy has to go on declining, and any prolonged decline of world oil prices will have massively negative ripple effects across the oil industry.

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Are oil and gas companies capable?

Written by David Bamford from PetroMall Investors, at least those in the UK, are deeply disillusioned with the oil & gas sector, not because they think the oil price is going to drop any time soon, nor because they prefer more fashionable stocks, but because they are mightily disappointed with PERFORMANCE! In some cases, this leads to very strong views.

At the June 2014 Finding Petroleum Forum the facts revealed were that:

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In Exploration, the last 18 months to two years have revealed abject performance, with poor success rates, whether in Mature areas such as NW Europe or in the Frontiers.

Developments are habitually late, or way over budget, or fail to deliver their production promises.

Production shortfalls are all too common.

An especially interesting commentary that emerged from the day's presentations and discussions was that this is almost certainly an issue of Capability. For example: 1. Boards, executive and senior managements may sometimes be ill-equipped to devise strategies, oversee their execution, and manage risks. Despite their high remuneration!

2. Petrotechnical and commercial teams oftentimes do not have the deep skills needed to deal with complex sub-surface, project and production operations issues. Perhaps "outsourcing" has gone much too far? But what alternatives are there?

3. The oil & gas industry seems almost uniquely incapable of learning from other industries, especially in how to turn its activities into a 'manufacturing' value chain.

The overall result is that European oil & gas shares have performed significantly less well than their North American cousins, some would say an order of magnitude less well.

I suggest that we have to accept the facts, the commentary and the result, stop being in denial (“the sector is out of fashion!�), and fix the actual problems.

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OilVoice Magazine | AUGUST 2014

The rise of Saudi TexKota Written by David Blackmon from FTI Consulting, Inc. I am fascinated by this report by Dr. Mark Perry of the American Enterprise Institute, and not solely because he quotes from a piece that appeared in this space last year (see Item #4). That piece deals with my belief that, although virtually all the attention related to America’s ongoing Shale Revolution from people outside of the oil and gas industry focuses on the technology of Hydraulic Fracturing (or “Fracking”), horizontal drilling is the true technological marvel that has enabled the industry to unlock the massive stores of oil and natural gas from shale rock over the last 15 years.

It is a truly amazing feat of engineering and science that enables drillers today to bore a hole 2, 3 or even more miles vertically below the surface, then literally bend heavy steel pipe to drill another mile or more horizontally through very dense underground rock, and ultimately hit a target no bigger than a quarter. Although the image of this industry that one typically sees portrayed on television or in the rare movie that deals with the subject matter is of wild, crude, hard-drinking, oil-covered roughnecks carelessly tossing around equipment at a filthy drilling sight, the truth about today’s drilling operations is that they are scrupulously clean, incredibly safetyconscious, and deploy a higher level of modern technology than almost any other industry on the face of the earth. It really is too bad the public seldom gets to witness that reality.

But back to Dr. Perry’s piece, and more specifically, item #3 in it, in which he posts the following: The combined oil output from America’s “Big Three” super-giant shale oil fields (Bakken, Eagle Ford, Permian) surpassed Canada’s crude oil production last September for the first time ever, and has exceeded Canada’s output in each of the last seven months through March of 2014 (most recent month for international oil production statistics from the EIA). As a separate oil-producing nation, those three oil fields in March, with a combined production 3.83 million bpd, would have been the fifth largest crude oil producer in the world, behind only Russia (10M bpd), Saudi Arabia (9.7M bpd), US (8M bpd) and China (4.1M bpd).

That, friends, is an amazing development, one made possible by the industry’s technological prowess, and one that has come about very recently. Indeed, if you look at Item #2 in Dr. Perry’s piece, you find that as recently as the beginning of 2011, these three fields combined were producing just about 1.5 million barrels per day. At that time, those fields produced less than 25% of overall U.S. oil production; today, they produce almost 46% of the nation’s daily oil output. And if one adds in the remainder of Texas’s oil production to this total, you find that these two states combined produce about half of all the oil produced in the U.S. today.

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So why is that, you might ask? The first, most obvious answer is that is where the resource is. It is a quirk of geologic fate that the great preponderance of these gigantic oil reservoirs happened to be formed beneath the respective surfaces of only two states. I say “preponderance� because the Permian extends into New Mexico, the Eagle Ford into Mexico, and the Bakken into Montana and Canada, but obviously the big volumes are coming from Texas and North Dakota.

Another answer to why these two states have produced such prodigious volumes of oil in recent years is less obvious but no less important: Public policy. It should be pretty obvious to any observer that, had the Eagle Ford happened to lie beneath the surface of New York, California or any number of other U.S. states, it would certainly not today be the biggest-producing oil field in North America. Frankly, if it were beneath New York, it may not have yet produced a single barrel of oil, given the manner in which the current Governor has stonewalled development of the state’s rich natural gas resources.

Or what if these massive oil reservoirs lay beneath federal lands in the InterMountain West? In Texas and North Dakota, operators are able to get drilling permits issued by state regulators in a handful of days. Seldom does the process take more than a month. Yet on federal lands, this process can consume many months or even years, as federal regulators pile an ever-increasing number of stipulations, studies, mitigations and planning requirements on operators.

Many reports have been written in recent years about the fact that the shale revolution has taken place mainly in states that have little federal interference or land ownership. While this is partly an accident of geography and geology, it is not entirely so.

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The rise of Saudi TexKota is no accident. It has happened because these two states are governed in ways that promote economic development and growth, and both are home to sophisticated regulatory structures that allow for such rapid growth to take place in something resembling an orderly fashion.

For the United States, this has been the single most important strategic energy development of the 21st century, whether the current Administration and its supporters in the anti-development community wish to admit it or not. The advent of Saudi TexKota has helped cut U.S. oil imports in half, and given our leaders geopolitical advantages the country hasn’t enjoyed for half a century.

All of which helps to explain why the anti-development forces have begun to focus so much of their attention on Texas and North Dakota in recent months. They clearly see where the Golden Goose is laying its proverbial eggs and feel it is their job to kill it. Any clear thinking person should fervently hope they fail in this endeavor.

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Reality blows oil seriously off course Written by Andrew McKillop from AMK CONSULT Friday the 13th For Oil Came On Friday 11th July In classic fashion market operators and manipulators gave a false signal to hopeful speculators, by nudging up oil prices on the Nymex, ICE and other oil markets, on Thursday 10th July. Then the market riggers crushed them, Friday 11th, with a 2.2% one-day crash of prices. To be sure we have to wait for Monday 15th trades to see if the new canonical oil price of $100-per-barrel can be set back in place like Humpty Dumpty, and will hold.

Chances are, it won't. Two-percent-daily price cuts can slash oil back to where it belongs at about $80 per barrel, quite fast. Marketwatch was forced to comment, 12 July, that US WTI and ICE Brent futures dropped below $101 a barrel and $107 a

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barrel on Friday to mark a fourth weekly loss and their lowest close in two months. It added that 'worries continued to fade over near-term threats to Iraqi oil production and Libyan production came back online'. It of course did not add that OPEC states are producing more than 35 million barrels a day! It said nothing about the real state and prospect of world oil demand - unlike the Mickey Mouse 'vision' of booming demand growth published by the IEA. Friday 11 July, West Texas Intermediate crude for August fell $2.10, or 2%, to settle at $100.83 on the New York Mercantile Exchange, a day after the Suckers Rally that nudged up prices before the big dip. Based on the most-active contracts, prices have not closed below $101 since May 12. The weekly loss on oil was roughly 3.1% compared with gold, which in 2014 to date, is the best-performing asset.

For amusement, we could ask Goldman Sachs how they viewed the year's prospects for gold in April or May! For sure and certain, GS will soon be diluting and backtracking on its 'cast iron certitude' that oil prices in 2014 could (they mean should) reach $125 a barrel by December.

Why Is Oil So Expensive?

Ask Goldman Sachs or the IEA. Ask them why, also on Friday 11 July, US natural gas prices struggled to hold minuscule gains in recent trading, for a weekly loss of 5.9%, to end at $4.15 per million BTU. This prices clean-burning natural gas in the US at exactly $24.07 per barrel equivalent. We can then ask why Goldman Sachs and the IEA seem to think Americans feel fine with natural gas at $24 a barrel - but also feel fine with oil at $100 a barrel? Their psychologists can maybe advise them how to treat their serious problem - but not an economist.

To be sure they can import coal from South Africa and Australia, including shipping costs, at a princely $29 per barrel equivalent - bu they can also buy the coal from US producers at as low as $15 per barrel equivalent. They do have a choice! With oil, they supposedly do not have a choice, but here again Goldman Sachs, the IEA, and the 'energy market maker banks' rooting for high-priced oil can advise us all why the price sticks so high. Oil is a 'rare and precious fluid', we suppose.

Stuck so high, it has to fall. This is Newtonian physics based on action and reaction being equal and opposite, it well fits the overpriced oil equation.

The IEA claims to have post-Newtonian quantum physics thinking on its side. It says that 'by about 2045 or 2055' the world must totally abandon all fossil fuel to Save The Planet. The global warming crisis, if you didn't know. So why worry about high oil prices?

Another question. Why worry about low oil prices either, if you want its production to wither and shrink to nothing? When the price falls, production will fall, right?

In the meantime bizniss is bizniss. The IEA with an approving nod from Goldman Sachs, the oil majors, OPEC and Russia will be talking up oil prices! On Friday 11 July, it did what it could to stem the rout for oil prices in a report saying that Iraqi production fell by 260,000 barrels a day in July to date, after violence in the north of

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the country, but increased supply from Saudi Arabia, Iran, Kurdistan, Nigeria and Angola offset the decline to leave OPEC production broadly steady at a claimed 30 million barrels a day, excluding Angolan and Iraqi output, and excluding temporary and unprogrammed losses of production capacity in member states (estimated at over 2.5 Mbd).

The IEA's Friday 11 July report was styled by the IEA as 'providing confirmation of traders' beliefs that the market isn't as tight as they previously feared, but no more than that,' Matt Parry, senior oil analyst at the Paris-based IEA told newswires in an email. Nice logic! Keep the high-priced party going.

Little Room For Complacency-Plenty For Fantasy The claim by all vested interested in extreme-high oil prices is 'no room for complacency'. They are obliged to make the false claim that the world oil supply / demand system hangs on a knife blade at all times, but we have to admit it is fantastic that among the most tireless workers of this policy line we find the IEA. This entity as noted above, wants us to abandon all fossil fuels by about 2050 (to save the planet as Al Gore has instructed, from his aviation kerosene-fueled Gulfstream jet)!

Obviously that abandonment of fossil energy includes oil - so we can move around on bicycles and feel free to breathe the green air in our eco-liberated cities. When oil is fully abandoned, we could ask the IEA (or Goldman Sachs) what the rational market price for oil would be?

Zero demand. Zero price.

The oil abandonment (or renounciation) model is obviously and firstly predicated on oil prices rising so high 'in normal market daily trading' that sensible and intelligent consumers will simply abandon the black fluid. Due to this model being the only one on offer, we are not allowed alternate models, where the oil price drops so low that nobody produces the stuff anymore.

This model however exists. World demand for bakelite, for example, is rather weak and not too many producers are in the market, these days. The ever-falling prices for cellphones do not do much for sales of producers like Samsung. The market is saturated.

The IEA's stress-based, crisis-borne model or paradigm wants us first to bear and support oil prices of for example $150 - $200 a barrel (well above the production cost of high quality whiskies or the best rum), and then suddenly renounce the black fluid.

Levered up by the exorbitant price of oil - but certainly not world coal or natural gas in the US - the magic Low Carbon energy transition also promoted by the IEA would take place. Too bad for any surviving oil producers! This fantasy model has nothing to do with any preceding historical transition in global energy economics and we can surmise is simply an expedient designed to rationalize and support extreme high oil prices.

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Its lifetime is obligatorily counted. On Friday 11 July, oil trading signaled the real world trend.

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The debt double standard for Canadian vs American energy producers Written by Keith Schaefer from Oil & Gas Investments Bulletin The 49th parallel isn’t just a border between Canada and the United States. It also represents an important line for the amount of debt investors are willing to tolerate in their energy producers.

Investors and CEOs have both learned the hard way. Canadian producers with more than 2X debt to cash flow–sometimes even 1.5:1–get no love from the stock market.

Typical conservative Canadian investors–they have almost no tolerance for debt.

South of the border, energy producers can carry big debt relative to their cash flows and still get high valuations from stock investors.

Comparing the recently acquired North Dakota Bakken producer Kodiak Oil and Gas (KOG) with Canadian Bakken producer Lightstream Resources (LTS) shows the stark difference.

There’s lots of similarities: For 2014 Kodiak guided for production of 39,000 to 42,000 barrels per day.

Lightstream’s 2014 guidance–updated for recent asset sales–is actually a little bit higher at 43,000 to 45,000 barrels per day.

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Conclusion: Production levels are similar.

They’re both light oil producers, so they similar levels of cash flow. Lightstream’s first quarter annualized EBITA was $753 million while Kodiak’s first quarter 2014 annualized EBITDA level is $716 million.

Conclusion: EBITDA levels are similar.

Cash flow dictates debt capacity. With similar levels of production and cash flow/EBITA it’s no surprise that Lightstream and Kodiak carry similar levels of debt– $2 billion and $2.3 billion respectively.

The Debt to EBITDA ratio of each company using its first quarter 2014 run rate annualized therefore looks like this: Lightstream – $2 billion / $753 million = 2.65 times Kodiak – $2.3 billion / $716 million = 3.21 times So it may surprise you to know the reputations of these stocks in the market; that is Lightstream having a weak balance sheet, and Kodiak doesn’t–despite Kodiak carrying more financial leverage than Lightstream.

This is the debt double standard and it shows up in how the market values these very similar companies.

Kodiak is about to be required by Whiting Petroleum (WLL) at a slight discount to where the stock has recently been trading.

The all-in (debt plus equity) price tag that Whiting is paying for Kodiak is $6 billion.

That means that Whiting is paying roughly $150,000 per flowing barrel and 8.4 times EBITA. Meanwhile the very similar Lightstream at its recent share price carries an enterprise value of $3.5 billion which means that it currently trades at $79,000 per flowing barrel and 4.6 times EBITA. If Lightstream were to trade at the same multiples of production and EBITA as Kodiak its share price would be $22 or $23. (To be fair, Canadian energy producers also trade at a small discount to US ones because of the Canadian “differentials”; our oil prices are lower because of pipeline constraints south, east and west of Alberta.)

Instead Lightstream’s shares languish between $7 and $8.

Now don’t take this to mean that I’m terribly bullish on Lightstream, because I’m not.

I know the rules of the game and I play by them.

This management team is in the penalty box for past disappointments. In late 2013 they cut in half a dividend that they had forever said was sustainable and then also

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subsequently reported a very disappointing 2013 reserve report. Add to that capital spending that went over budget in 2013 resulting in very poor capital efficiency and you have a group that has a lot to prove.

I’ve used Lightstream because it was very similar to Kodiak in size, leverage and oil weighting.

Lightstream’s valuation predicament clearly shows how debt averse Canadian investors are relative to their American counterparts.

Other Canadian producers that carry much less leverage have valuations that are very similar to Kodiak’s. Companies like Crescent Point Energy or Raging River which have debt to EBITDAratios at 1X or less regularly trade for $150,000 per flowing barrel or higher.

Take away the debt and the assets are valued similarly.

There Are Other Variables To Consider – A Big One Is Decline Rate Kodiak and Lightstream are similar but there are differences.

Lightstream is diversified across a few oil plays while Kodiak is focused on the Bakken/Torquay. The profitability and payout times of the wells that each company is drilling is similar, but Kodiak’s wells are much more prolific and expensive to drill.

One big difference that should actually make Lightstream’s production more valuable than Kodiak is–Lightstream has a lower decline rate; i.e. the rate at which its production is declining naturally is lower than Kodiak’s.

Both companies are pure plays on horizontal oil production. In the first couple of years these horizontal wells have extremely high rates of decline. Production at the end of the first year of the life of a well can be down by more than 60%.

By year three or four those decline rates settle in around 20% per year and get a little better from there.

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Both Kodiak and Lightstream have close to 40,000 barrels per day of production, but because it has been growing so rapidly Kodiak’s production is much newer than Lightstream’s.

That means that it is declining much more rapidly and is going to require considerably more capital to just offset those declines in the coming year.

With two-thirds of its production less than two years old, Kodiak likely has a corporate decline rate that exceeds 40%. Lightstream which has more mature production has a decline rate that is around 27%. Over 40% is bad, under 30% is really good for light, tight oil plays.

Fair Or Not–These Are The Rules of The Game Like it or not (and I’m sure companies like Lightstream vote “not”) this debt double standard is the rule for investing in Canada. A consequence of that is Canadians use more equity and have more shares outstanding than American producers.

If a CEO doesn’t want his company to suffer from a big valuation discount, he or she has to run with a clean balance sheet.

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OilVoice Magazine | AUGUST 2014

What if oil companies applied cybersecurity tactics to safety?

Written by Loren Steffy from 30 Point Strategies The American Petroleum Institute is working with several large U.S. oil companies to assemble a team of cybersecurity specialists that would help identify and prevent malicious software attacks against the computers that control the country’s energy infrastructure. Led by an executive for Dallas-based Hunt Oil, the group will serve as a clearinghouse of sorts for threats to automated systems.

By improving communication among oil companies, the group, known as the Oil and Natural Gas Information Sharing and Analysis Center, hopes to get companies working together to thwart attacks that could cripple offshore rigs, refineries, pipelines and other equipment. The move comes after a hacker group that had already targeted defense contractors shifted its focus to energy companies in March.

The approach makes a lot of sense. After all, the potential for hackers to target energy company computer systems poses a mutual threat that is best addressed when companies combine their efforts.

The oil and gas industry has shown remarkable solidarity when it comes to addressing what it perceives as a common outside threat, whether it comes from hackers or new regulations the industry considers onerous. It’s been far less willing, however, to take such a collaborative approach to confront threats from within its own ranks.

While it’s at it, the API should consider taking its collaborative approach to cybersecurity and applying it to an even bigger concern: safety.

In dealing with the threat that safety — especially in offshore drilling — poses to the industry’s future, the API has taken a far different approach than it has with cybersecurity . While it outlines a series of safety “best practices” for its members, these are voluntary guidelines. Rather than holding members to a higher standard, API too often winds up defending the operators with the poorest safety practices.

In the wake of the Deepwater Horizon disaster, regulators embraced a slew of new, prescriptive rules designed to prevent another catastrophe. Offshore regulators, though, still face the daunting task of monitoring a growing number of rigs and production platforms in the Gulf of Mexico, even as they struggle to find enough people with the technical expertise to complete the task.

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While the threat of a cyber attack poses a significant potential threat to the industry, the danger of another Macondo-style disaster is even greater. The industry won’t get a second chance in the Gulf. API could help the industry avert this disaster by pushing for a collaborative process in which a panel of company experts review the safety programs and well designs of offshore operators. At the same time, the API should urge is members to embrace global safety standards and reduce systems that can be compromised by the actions of one individual.

These sorts of measure are used by other high-risk industries that depend on high reliability. Airlines, for example, don’t allow a single person to be in a position where their actions, by themselves, could lead to system failure.

By adopting a set of global safety standards, and creating a panel to ensure companies are following those standards, the API could take the lead in improving operations in the Gulf of Mexico, and perhaps the world.

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Oil & Gas M&A in upstream sector reaches $51.3 billion in Q2 2014 Written by Mark Young from Evaluate Energy

Following a lacklustre first quarter for M&A activity in the oil and gas upstream sector, the second quarter of 2014 saw a spectacular rebound according to anaysis from Evaluate Energy. The total upstream deal value of US$51.3 billion is the highest single quarter total since 2012.

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OilVoice Magazine | AUGUST 2014

Quarterly Upstream Deal Value by Deal Type 2012-2014

Source: Evaluate Energy M&A Database The majority of the increase in global upstream deal activity is attributable to companies and assets based in North America, where the total value of upstream deals announced increased for the fourth quarter in a row. Deals to acquire North American upstream assets or businesses made up 47% of the total deal value (US$24.3 billion) in the second quarter of 2014.

Source: Evaluate Energy M&A Database

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OilVoice Magazine | AUGUST 2014

American Energy Partners LP Continues with Utica Acquisitions Acquisitions by North American companies also made up 47% of the quarterly total upstream deal value. Amongst the biggest-spending North American companies this quarter was the Aubrey K. McClendon-led American Energy Partners LP (AELP), which made large acquisitions in the prolific Permian Basin (US$2.5 billion) and the Marcellus and Utica shale plays (US$1.75 billion) in early June. McClendon was an early champion of the Utica shale in his Chesapeake Energy days and the acquisition continues to show that his faith in the play's potential has not wavered; this US$1.75 billion deal was AELP’s fourth acquisition this year to include a position in the Utica shale.

Apache, Devon, Encana & Freeport-McMoRan Streamline North American Positions On the whole, AELP’s activity was a rare case as most other acquisitions in the quarter of this size were accompanied by a similarly-sized sale of assets elsewhere; it seems many North American companies are focused on streamlining positions rather than making large acreage gains like AELP. The motivation behind this streamlining of strategies will most likely be high North American production costs as well as low gas prices that have caused major rethinks for many companies trying to keep netbacks in line with shareholder expectations.

Apache Corp., Devon Energy, Encana Corp. and Freeport-McMoRan Copper & Gold Inc. (FCX) are four big North American companies who conducted the highest profile restructurings within the region this quarter.

Apache continued its US$4 billion divestiture plan to aid debt repayment and share buybacks by completing the US$1.4 billion sale of the Lucius and Heidelberg Gulf of Mexico shelf prospects to FCX and entities exercising pre-emptive rights over the assets. FCX had originally agreed to acquire the full stakes held by Apache in the assets but eventually ended up contributing US$919 million of the US$1.4 billion Apache received in consideration. This acquisition by FCX was funded by the biggest single deal of the second quarter, an agreement to sell 45,500 acres and 59 million barrels of proved reserves in the Eagle Ford shale to Encana for US$3.1 billion. FCX – having increased its focus on the Gulf of Mexico - will use the rest of the proceeds from this sale to redeem $1.7 billion in senior notes. In turn, Encana made a couple of sales of its own to fund this Eagle Ford acquisition. In April, the

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company agreed to sell some East Texas assets for approximately US$486 million and then in June, Apollo Global Management LLC – a New York-based private equity investor – acquired the company’s Bighorn Alberta Deep basin assets in Canada for US$1.8 billion.

Devon completed the majority of its own restructuring plan last quarter, completing the biggest deal of 2013 to finalise its entry into the Eagle Ford shale for US$6 billion, as well as announcing the sale of non-core assets in Canada to CNRL for US$2.9 billion. The final piece of the company’s restructuring jigsaw – a US$2.3 billion deal that will see Linn Energy acquire Devon’s non-core onshore assets - was announced on the very last day of the second quarter. Once this final deal is complete, the restructuring process for Devon will be over and it is hard to argue that it has not gone well; the company now has a premier position in one of the US’ most attractive shale plays, lucrative oil and condensates will have risen to form 60% of the company’s oil & gas production by year end and net debt will have been reduced

by US$4 billion.

Outside of North America, further large restructuring operations took place this quarter and amongst the highest profile of these was Hess Corp’s latest deal on its way to becoming a single-resource play company. Hess agreed to sell its Thai business to state-backed PTTEP for US$1 billion. In Chad, Chevron decided to sell its 25% stake in producing assets and a pipeline to the Central African country’s government for US$1.3 billion. These deals made up the majority of the total statebacked deal value this quarter, as state-backed entities have had a very quiet 2014 with only US$3.2 billion of deals in the second quarter after a first quarter total of US$1.8 billion – in Q3 and Q4 2013 state-backed companies were involved in nearly US$25 billion of upstream deals combined.

Investment Firms Active in Q2 2014 Apollo Global Management was not the only investment firm to be active in the upstream M&A arena in the second quarter. Morgan Stanley completed Repsol’s exit from Argentina by acquiring the final 11.86% stake in YPF SA held by the Spanish major for US$1.4 billion including debt, whilst various investment firms were involved in the combined US$3 billion acquisition of a 9.5% stake in Australia’s Woodside Petroleum from Royal Dutch Shell. This willingness of private investment firms to buy interests in global E&P assets speaks volumes for the confidence held in the sector right now, despite ever-climbing operational costs seeming to hinder the profit-

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OilVoice Magazine | AUGUST 2014

making abilities of upstream companies worldwide.

This report was created using the Evaluate Energy M&A database. The database includes every upstream and downstream acquisition since 2008. Evaluate Energy provides clients with efficient data solutions for oil and gas company analysis.

Alongside our M&A product, Evaluate Energy also has historical financial and operating data for 300+ of the world’s biggest and most important oil and gas companies, a global assets database and a North American shale-focused product.

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Top 10 Upstream Deals in Q2 2014

Acquirer

Encana Corporation

Various Investment Firms

Woodside Petroleum

Target FreeportMcMoRan Oil & Gas LLC and PXP Producing Company LLC A 9.5% stake in Woodside Petroleum from Royal Dutch Shell A 9.5% stake in Woodside Petroleum from Royal Dutch Shell

Target Brief Description Country

United States

Total Acquisition Cost (US$000s)

Encana acquires 45,500 net Eagle Ford acres in heart of the 3,100,000 oil-rich portion of the play

Royal Dutch Shell plc disposes 9.5% of its share in Woodside Australia 2,985,653 Petroleum Limited to a range of equity market investors Woodside Petroleum Limited buys back 9.5% of its own Australia shares from Royal Dutch Shell plc

Det Norske

Marathon Oil Norge AS

Norway

American Energy Partners, LP

Enduring Resources, LLC

United States

Linn Energy

Devon Energy Corporation

United States

2,679,965

Det Norske Oljeselskap ASA acquires Marathon Oil's wholly 2,661,049 owned subsidiary, Marathon Oil Norge AS American Energy Partners, LP, through its subsidiary American Energy – Permian Basin, LLC, 2,500,000 acquires approximately 63,000 net acres from Enduring Resources, LLC Linn Energy acquires Devon's non-core US oil and gas 2,300,000 properties in the Rockies, onshore Gulf Coast and Mid-

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OilVoice Magazine | AUGUST 2014

Al Mirqab Capital SPC

Heritage Oil Plc

Apollo Global EnCana Management, Corporation LLC

Various

Canada

American Energy Partners, LP

East Resources, Inc. and an United unnamed private States company

Glencore Xstrata plc

Caracal Energy Inc.

Chad

Continent regions Energy Investments Global Ltd, a wholly-owned subsidiary of Al Mirqab Capital SPC makes a cash offer to acquire Heritage Oil Plc Jupiter Resources, held by Apollo Global Management, acquires Encana's Bighorn assets in the Alberta Deep Basin American Energy Partners, LP (through subsidiaries) acquires approximately 75,000 net acres in the Marcellus and Utica shale plays from East Resources, Inc. and an unnamed private company Glencore Xstrata plc acquires Caracal Energy Inc.

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1,874,737

1,800,000

1,750,000

1,633,094