Looking for Oil and Gas Values, Not Value Traps

Eric Nuttall: Looking for Oil and Gas Values, Not Value Traps

Source: George Mack of The Energy Report  (6/30/11)

Sprott Energy Fund Portfolio Manager Eric Nuttall wants an edge when he can find one. He's bullish on oil, but he prefers to play the good oil story, not the commodity. And even though he's bearish on natural gas, he's finding names that may provide exceptional growth. Eric shares his best ideas in this exclusive interview with The Energy Report.

Companies Mentioned: Apache Corporation - Bankers Petroleum Ltd. - Cheniere Energy Partners L.P. - Encana Corporation - EOG Resources, Inc. - Legacy Oil & Gas Inc. - Open Range Energy Corp. - Painted Pony Petroleum Ltd. - Suncor Energy Inc. - Vero Energy Inc. - WestFire Energy Ltd.

The Energy Report: In 2010, the Sprott Energy Fund outperformed its peer S&P/TSX Capped Energy Index (32.6% versus 11.7%). In fact, the fund outperformed the index in five out of the last seven calendar years. What's the formula here?

Eric Nuttall: We really try to look for opportunities where we have an edge over our competitors. That typically leads us into the small- and mid-cap energy space, where we think the outlook is very positive over the next couple of years. We believe the fundamentals for oil are now very solid. And we think there's been a huge disconnect in the performance of oil and gas (O&G) stocks relative to what the commodities have done.

TER: You're bullish on oil. Tell us why.

EN: What I fall back on is supply and demand data, which I find to be very reliable. Despite an increase in weak economic data points in several developed economies, I still believe that the world oil market will tighten heading into the fourth quarter of this year (Q411). We entered 2011 in a state of being undersupplied by about 1 million barrels of oil per day (MMbpd). So, it wasn't a surprise to me back at the last OPEC meeting that Saudi Arabia was trying to increase actual production by about 1 million barrels. The recent release from the Strategic Petroleum Reserve (SPR) is nothing but a politically motivated move to try to suppress the price. While this may create a ceiling of around $90/bbl for the next several months, demand has been surpassing supply and the market is becoming increasingly tight.

The oil demand story is about emerging economies. China was responsible for 33% of incremental demand in 2010, and in the most recent data from May, demand is up 13% year-over-year (YOY). China now consumes more than 9 MMbpd, a net change of over 1 MMbpd. I'm looking for demand destruction in the developed economies; however, incremental net demand out of China, India and even parts of Africa more than outweighs that demand destruction. The oil market is tight today, and I think that it'll continue to get increasingly so. Today, we consume 89 MMbpd globally; if the world continues to increase demand by roughly 1–2 MMbpd per year, it's very easy to see a scenario in which OPEC spare capacity could get down to 1 MMbpd within the next two years. In that environment, I think the price of oil has to go higher.

TER: When you last spoke to The Energy Report in the fall of 2010, you said that equity valuations—not commodity prices—would be your guide. Since that time, Brent Crude is up about $30/bbl or about 40%. Have you become a bit more commodity-driven since then?

EN: I wouldn't say so. I think Brent is a more relevant benchmark to use than is West Texas Intermediate (WTI) because of the landlocked-storage issues that Cushing, Oklahoma has been experiencing. So, when I look at a $105/bbl Brent price, it tells me that world oil demand is very, very strong. But at the same time, my forte is not top-down analysis of the commodity markets—it's trying to find mispriced stocks. I personally believe that global supply and demand now support a price of approximately $100/bbl WTI, so you could call it about a $110/bbl Brent price. I think that price level is defendable for the next couple of years, with an upward bias toward maybe $5–$10/bbl per year.

In that environment, I think there are some incredibly cheap oil stocks in the sub-$2 billion market-capitalization range that are trading at under 4x enterprise value to cash flow (EV:CF); they are growing production by 30%, 40%, 50% per year and they have very clean balance sheets and a lot of exposure to emerging plays. It's the best of all worlds. You've got dirt-cheap stocks with a tremendous amount of upside. The amount of fear in the marketplace today is the highest I've seen since 2009. One of my best lessons from the Great Recession is that where there's fear, there's opportunity. I think there's a tremendous amount of opportunity in this subset of the market right now.

TER: Then, clearly, you are finding compelling valuations.

EN: Without question.

TER: And we'll get to that, but let me bridge to this. Are you currently bearish on natural gas?

EN: I am. I believe that it's going to be capped at around $5/Mcf (thousand cubic feet). I think we're stuck in a $4–$5/Mcf trading range until 2015, at which time North America will become an exporter of natural gas. In Canada, the Kitimat LNG (liquefied natural gas facility) will be constructed by around 2015. Kitimat is jointly owned by Apache Corp. (NYSE:APA), EOG Resources Inc. (NYSE:EOG) and Encana Corp. (TSX:ECA; NYSE:ECA). In addition, Cheniere Energy Partners L.P. (NYSE.A:CQP) got expanded approval to be a natural gas exporter. I think we're going to see a lot more regasification facilities on the Gulf of Mexico seek approval to become exporters.

Technology has unlocked an unbelievably large amount of natural gas that is now quite economic at low prices. Four or five years ago, I would've said the required price to achieve a decent economic threshold was $7/Mcf. Today, I think that threshold is about a $4–$5/Mcf price among most of the shale plays, which would be Eagle Ford, Haynesville and Marcellus—the largest sources of new supply in both the United States and North America. Rig count has continued to expand in all of those plays. Even in a depressed natural gas price environment, producers continue to drill.

Demand is growing as a result of coal substitution and lower nuclear power plant utilization, but l still think supply is overwhelming demand. Again, until we become an exporter, we're looking at a $5/Mcf ceiling price because if we ever get above that, every single gas company in North America will be trying to hedge to be able to lock in a very active capital-expenditure (capex) program.

TER: So, you're saying there's a real arbitrage opportunity for some nat gas producers to export to Asia and Europe?

EN: Yes, there's a huge arbitrage in that. The global LNG pricing on average has been around $10–$12/MMBtu (million British thermal units). There are times when it spikes due to seasonal factors, but there's a huge price differential. That's why I think the plays that are close to key export terminals are going to become highly strategic. Some of my top holdings are companies involved in what I think will become increasingly strategic areas.

TER: For many reasons, energy has been a natural growth sector. How do investors play this today?

EN: I look for companies in which I think I have an edge in my analysis to determine if they truly are undervalued, or whether they're just value traps. Because we've seen names fall 10%–15% in May, and then by another 15%–20% in June, you could almost throw a dart at a board and make money in the energy sector over the next couple of months. But where I'm finding value, and where I think you get the best risk/reward, is in companies that are levered to oil that are in that sub-$2 billion market-cap space. There are also opportunities in the natural gas space. In a $4–$5/Mcf gas-price environment, some companies are earning about a 75% margin. I'm looking where the risk/reward of an investment opportunity is highly, highly skewed to the upside.

TER: Skewed to the upside. Could you give me an example of that?

EN: Well, we could walk through some of my top holdings. That's probably the best way to understand my style.

TER: Sure.

EN: In terms of size, my largest current position is Legacy Oil & Gas Inc. (TSX:LEG). It's a $2 billion-market cap light oil company, and it's a case study of how we try to look at things differently. There was a management change within a major shareholder, Fidelity Investments, and the manager had to blow out 18 million shares. That took the share price from $17.50 down to around $11.50; not for any fundamental reason—it was due to fund flow. The stock trades at around $12 today, but I was aggressively buying at around $12.50 and was buying every share I could at around $11.50.

When I started buying LEG, I was paying the lowest multiple of price-to-cash flow in its corporate history. and I thought my downside was limited to commodity and market risk. I knew the company had very significant exposure to several emerging plays, including the Spearfish in North Dakota and the Alberta Bakken, which is an emerging tight oil play. So, I paid a very low multiple and got all of the upside free. I could see the stock at $16. So, while a 33% upside from today's level doesn't sound super sexy, it's decent; and I think my downside risk is very low. The company is managed by, in my opinion, one of the best light oil teams in the business, which is comprised of proven value creators; and the balance sheet is very clean.

TER: I note the company went from operations cash flow of $26.3M in Q110 all the way up to $43.9M in Q111. Can that kind of growth continue?

EN: Yes, I'm looking for more than $300M cash flow in 2012. That would put the company at 6.7x cash flow today, and I think it can grow production by 15%. Legacy's about 80% levered to the price of light oil. It's got all of the different aspects I look for.

My second-largest position is Painted Pony Petroleum Ltd. (TSX.V:PPY.A), and this is an example of how you can be bullish on natural gas names without necessarily being bullish on natural gas. The company has a market cap of about $700M and, in terms of production, it's equally split between oil and natural gas. Painted Pony has assets in Saskatchewan, which is typically a light oil-weighted basin, and northwest British Columbia, which is a real upside. But what I really liked is its very clean balance sheet; this is a very debt-averse company. PPY has a five-year drilling inventory in the southeast region of the Saskatchewan Bakken play, where the economics or hurdle rate for the required price of oil is very, very low. When I started buying the stock, it was trading very cheaply on current production. Legacy appears to be in the sweet spot of the Montney Shale play in Canada. I think fair value on existing production is up to $30, but I don't think the company will be around long enough to realize that.

TER: So, 175% upside from here?

EN: Again, I don't think it will be around that long. It could be easily taken out from $17.50–$20/share over the next year or two. Internally, I think fair value is around $20/share. So, I'd be comfortable saying it's close to 100% potential upside.

My third-largest holding is WestFire Energy Ltd. (TSX:WFE), which is almost a pure play on an emerging tight, light oil play called the Viking Formation in Canada. The company has spent several years aggregating acreage in this play, and I believe it has about 800 risked locations. If one believes in $100/bbl oil, then that works out to about $25 of risked value per share—and the stock is trading at $6.85 now and at 3.9x 2011 cash flow. It's very, very cheap on current production. WFE's balance sheet is healthy, and I think production will grow by more than 20% in 2012 over 2011. I like the management; the team members have a lot of their own skin in the game, so they're highly motivated to sell the company when the right time comes.

TER: WestFire was your largest holding at the end of May, was it not?

EN: It would've been a few months ago. I haven't sold any shares. It's been weak relative to a couple of other names.

My fourth-largest holding is a company called Open Range Energy Corp. (TSX:ONR). This is an interesting name because if we had talked nine months ago, I would've told you it was an economic natural gas company that was growing production strongly. But what's really transformed the story is a very positive uptake on a new service business called Poseidon Concepts. It's simply a way to store water that's used to fracture stimulate natural gas wells. What it's created is almost like a very large, inflatable aboveground swimming pool, as opposed to hauling 20 or 25 truckloads of steel tanks. So, there's a cost savings to ONR of more than $100,000 per job.

This business has grown from nothing to a run rate of about $80 million of EBITDA, which is just phenomenal. So, that service business is growing strongly and the free cash flow from it is being used to grow the natural gas business in the Wilrich, where there's phenomenal natural gas economics. The company has very strong growth on the natural gas business and, at the same time, there's very good uptake on the service business. And, it's dirt cheap.

TER: You're a real value seeker, aren't you?

EN: Well, it's important to distinguish between a value stock and a value trap. A value stock can be a cheap stock with no catalyst to revalue the company. I always look for names where I think my downside's limited because it's trading at a cheap multiple based on current production. At the same time, there has to be some catalyst to the name—otherwise, the stock can languish at a cheap multiple for years. Sometimes cheap stocks are cheap for a reason; my job is to try to find those opportunities where, in my opinion, the market is looking at something incorrectly.

TER: You were going to mention another one?

EN: After Open Range would be Bankers Petroleum Ltd. (TSX:BNK). It's fallen from a high of $10 around the beginning of March to near $7, and so the stock's down 30%. At the same time, it's marked off of Brent oil, and it's developing the largest onshore oil field in Eastern Europe, the Patos-Marinza field in Albania. Bankers is producing around 12,000 bpd, and will be exiting at around 18,000–20,000 bpd at the end of this year. It's been very successful at employing Canadian technology in an old field to rehabilitate it and to grow production, primarily using horizontal wells with good success.

TER: Again, it's under a $2 billion market cap, which is where you're comfortable.

EN: Yes, it's that sweet spot. Larger companies are very difficult. With a Suncor Energy Inc. (TSX.V:SU; NYSE:SU) or an Encana, which is a $40–$50 billion market-cap company, it would be very difficult for me to have an edge over my competitors. If I buy that company, I should expect to do as well as the index. My unit holders are not paying me to perform as the index would. They're looking for me to beat it. I'm looking for opportunities in which I've got edge and that will typically lead me to a sub-$2 billion market.

TER: Do you want to mention one more company?

EN: Another one would be Vero Energy Inc. (TSX:VRO), which is a stock that's kind of fallen out of favor with the marketplace. The management's done a very good job of growing production over the years. On a production-per-share basis, it's upward of around 22% from 2009 until now, yet it trades at a low multiple. VRO's trading sub-4x EV to cash flow, despite management's pretty good execution. Production is growing very meaningfully, and the company is increasing the component of liquids in the production stream. My hope is that Vero will sell itself at some point this year or merge with another company creating a high dividend-paying corporation and one exploration entity that the Vero management team could lead.

TER: Eric, these are very interesting names. Thank you very much.

EN: Thank you.

Eric Nuttall is a portfolio manager with Sprott Asset Management (SAM). He joined the firm in February 2003 as a research associate and was subsequently promoted to research analyst in 2005, associate portfolio manager in 2008, and then to portfolio manager in January 2010. Eric is lead portfolio manager of the Sprott Energy Fund, along with Eric Sprott, and he also comanages the Sprott 2010 Flow-Through Limited Partnership with Allan Jacobs. In addition to his responsibilities for those funds, Eric supports the rest of the Sprott portfolio management team in identifying top-performing oil and gas investment opportunities. Eric also contributes to internal macro-energy forecasts, and his insight into emerging unconventional plays has been covered in several financial publications, such as The Wall Street Journal, Asia and Barron's. Eric graduated with high honors from Carleton University with an Honors B.S. in international business.

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DISCLOSURE:
1) George Mack of The Energy Report conducted this interview. He personally and/or his family own shares of the following companies mentioned in this interview: None.
2) The following companies mentioned in the interview are sponsors of The Energy Report: None.
3) Eric Nuttall: I personally and/or my family own shares of the following companies mentioned in this interview: Painted Pony, Westfire, Bankers and Open Range. I personally and/or my family am paid by the following companies mentioned in this interview: None.

Shell Shares Safe Shale Principles

Today, from the 2011 Aspen Ideas Festival, Shell makes its Global Onshore Tight/Shale Oil and Gas Operating Principles available to the public with examples of how the company delivers them. Shell has a rigorous set of five global operating principles that provide a tested framework for protecting water, air, biodiversity, and the communities in which Shell operates.

Shell is openly sharing these operating principles to address public concern about tight/shale oil and gas development - especially regarding hydraulic fracturing – encourage feedback and challenge from our stakeholders, and drive continuous improvement. Shell also supports regulation and enforcement that reinforces responsible operating practices and continues to improve the industry's overall performance.

"We understand there is concern around the development of shale gas, and we must give the public more knowledge of how we operate," said Marvin Odum, President, Shell Oil Company. "People have asked the industry for transparency; we have listened and are responding."

Specific on water, hydraulic fracturing has attracted a great deal of attention in recent months. As an example of how we deliver these principles, which are now described online, Shell mandates a stringent well construction standard that focuses on the use of safe drilling and completion processes, including reducing the risk of water contamination.

Further, Shell supports the disclosure of chemicals used in hydraulic fracturing fluids, monitoring of groundwater, and a reduction in the amount of water used in the drilling process. Shell does not fracture wells unless it has pressure tested the wellbore for integrity. And, the company recycles as much water at each project as reasonably practicable. For example, in the Marcellus Shale, Shell recycles almost 100% of produced fluids, substantially reducing our fluid waste and reducing the amount of water volumes needed for hydraulic fracturing.

In the last decade, the industry has discovered an abundance of natural gas. Of the world's 250-year supply of gas estimated by the International Energy Agency (IEA), almost half is contained in shales, tight sandstones, and coal beds. More than one-third of the global gas-production increase, forecasted by the IEA over the next 25 years, could come from these sources.

"If the innumerable benefits of natural gas are to be realized, we must address the concerns of citizens and share the principles that we hold ourselves to at Shell," said Odum. "These principles manage the risk we know exists when producing energy, but just as importantly, they demonstrate our operational integrity and focus on collaboration, underpinning our belief that natural gas can be produced safely and responsibly."

IHS: capital costs increasing

6/29/2011

In the newest IHS report, upstream capital costs rose 5% from 1Q 2010 to 1Q 2011, largely because of rising steel, equipment and labor costs. On 29 June 2011, IHS said its Upstream Capital Cost Index indicated construction costs of upstream oil and gas facilities rose 5%, moving the index score to 218.

The Upstream Operating Costs Index also reported operation costs of these facilities rose 2%, moving its index score to 178. Using values from the year 2000, the IHS reports that capital costs of $1 billion in 2000 will now cost $218 billion. Also, operating costs of $100 million in 2000 will now cost $178 million. According to the release, the latest increase is pushing costs to pre-recession levels.

'Reflecting expectations for stronger oil and gas demand is taking the form of an increased rate of new project construction,' Daniel Yergin, IHS CERA Chairman, said.

After declining 34% in 3Q 2008, upstream steel costs continued a year-long increase, rising 13%. As costs for all steel-making raw materials increased, the steel-manufacturers aggressively increased prices to offset the low inventory. Like a domino effect, the rising steel costs increased the equipment costs that suppliers passed along to operators.

Driven by the demand in South America and Asia, the report showed construction labor and engineering and project management costs increased by 9% and 6%. North America's growth continues to be slow, as the continent is still recovering from the recession and the oil spill in the Gulf of Mexico, according to IHS.

Subsea equipment costs are up by 6% as new orders continue to increase, largely due to the activity offshore Brazil and in the North Sea, which compensates for the limited decline in North America and Asia.

Offshore rig and offshore installation costs, however, are the only two markets to reports a decline, due to low activity in the Gulf of Mexico and increased supply of those entering the market. While costs declined, the report says, these two markets have shown an upward movement in the latter half of the six-month period.

The IHS report projects all operating costs to continue to rise in 2011 due to the competition of labor and the rising costs of steel and consumables such as chemicals, food and fuels.

by: Katie Jernigan,
kjernigan@oilonline.com

Nuclear Shutdown Threatens Japan's Economy

Nuclear Shutdown Threatens Japan's Economy

Source: Industrial Fuels and Power  (6/27/11)

"Most-pessimistic scenario sees growth slashed by 1.6% in FY12/13."

Japan urgently needs new safety guidelines on nuclear power plants to avoid them being shut down completely by next April, which would see a 1.6% cut in economic growth, according to Kazumasa Iwata, president of the Japan Center of Economic Research.

"In the most pessimistic scenario, growth will be shaved by about 1.6% in fiscal 2012/13, with the effects still felt until fiscal 2020/21, when growth will be lowered by about 0.5%," Iwata told Reuters in an interview.

To avoid this from happening, the government must clear three conditions. Firstly, it must carry out a thorough investigation of how the nuclear crisis occurred and what new steps could prevent the same mistakes being made. In addition, globally acceptable safety standards must be established and an independent regulatory body that decides on reactor restarts must be set up.

"These steps should be taken by the end of the year. Japan is battling against time, but what the government is doing is putting priorities in the wrong order," said Iwata, a former deputy governor of the Bank of Japan. "Reactors that meet thorough safety standards should be restarted. Otherwise, one must question whether Japan's economy can be sustained," he said.

While he considers the country's policy of boosting energy self-sufficiency and cutting CO2 emissions through the use of nuclear power still valid, he said that the country must consider different options for its energy mix. Innovations in technology would allow large-scale production of solar panels and bring down this energy source's cost, he said. Moreover, other options are wind and geothermal power.

New technologies reduce pre-commissioning time, cost

The increasing number of subsea and deepwater developments brings new challenges when there are no surface connections to the pipeline available for testing and pre-commissioning.

Once constructed/installed, such subsea and deepwater systems still must undergo certain pre-commissioning and commissioning operations, from initial flooding, gauging and testing, up to final start up.

While the provision of such services in shallow water and topside-to-topside developments is routine, the same services at water depths in excess of 1,000 m (approx. 3,300 ft) pose many challenges. These challenges, and the current/planned technologies to address them, include:

• Flooding and pigging subsea pipelines using a remote flooding module (RFM). This enables the use of available hydrostatic head to flood and pig subsea pipelines while meeting the project requirements in terms of pig speed, filtration, and chemical treatment.
• Use of ROV driven pumping units to complete flooding and pressurization. By using the hydraulic power from a work class ROV to power a custom built pump skid connected onto the RFM, all pigging and pipeline testing can be performed subsea.
• Use of smart gauge tools (SGT) to gauge pipelines without using aluminum gauge plates. This allows the gauging of lines with reduced bore PLETs at each end. Also, this gives the ability to communicate the result of the gauging run through-wall without the need to recover the gauge plate to surface. This allows testing without pig recovery.
• Use of subsea data loggers to record pressures and temperatures during subsea testing, and use of systems to transmit this data to surface in real-time during the test.

The need for new and improved pre-commissioning technologies is expected to be particularly acute in the Asia/Pacific market, where there has been a significant increase in deepwater pipeline projects over the past few years.

Pre-commissioning defined

This flow chart illustrates the pre-commissioning process as typically applied to oil pipelines. The process for gas lines is similar but involves additional steps prior to handover such as removal of hydrotest water (dewatering), drying, MEG swabbing, and nitrogen packing (not covered here).

Subsea pipeline flooding

The first subsea pigging units were conceived and developed to overcome problems associated with flooding and pigging pipelines in deepwater. The latest subsea flooding device is the BHI Remote Flooding Module, which essentially achieves the same objectives using the latest ROV and subsea technologies. The RFM is a subsea flow control and regulation system. Once positioned on the seabed and connected to the pipeline to be flooded or pigged via the HP loading arm, it is "operated" by the ROV opening the valves to the pipeline. The hydrostatic head of the sea then enters the pipeline through the RFM because of the differential pressure between the inside of the pipeline, which is at atmospheric pressure, and the sea.

The pre-commissioning process as typically applied to deepwater oil pipelines.

Seawater enters the RFM via a filter manifold with a specified filtration level, usually between 50 and 200 microns. It passes through a venturi device, which creates a small pressure drop in the onboard flexible RFM chemical tanks which connect to the water flow pipework. This small differential pressure induces anti-corrosion chemicals into the water flow at the desired rate. This is pre-set prior to deployment and adjusted subsea by ROV if necessary.

The chemically treated water is held to a pre-determined rate by a flow regulation system. This maintains the water flow at the desired speed to match specified or optimum pig speed or flooding rates. Again, this can be pre-set prior to deployment and because the rate is controlled at a steady level, the chemical inducement is assured throughout the entire "unassisted" operation. A boost pump is required to complete final pigging operations due to pressure equalization. This pump is ROV driven, usually operated when the ROV returns to disconnect and recover the RFM, and in deepwater is required only for a very short time.

 

The vessel and ROV can leave the unit in isolation on the seabed during the unassisted operations and go on to other tasks. There is no need for connection to anything other than the pipeline. Onboard batteries power data-logging instrumentation which logs flows and chemical rates. Visual readouts allow the ROV to check status before it leaves and when it returns.

The RFM is positioned on the seabed by the ROV and connected to the pipeline to be flooded via the innovative rigid loading arm pipe system. The ROV then positions itself on the unit's roof from where it can monitor instruments and operate valves to manage the initial stages of the operation and adjust chemical control valves as needed.

Filtration and chemical treatment specifications are met by onboard facilities. Chemicals are stored in flexible tanks and introduced by a venturi system regulated by detecting changes in the water flow through the unit, and automatically adjusts the chemical flow accordingly.

To summarize, the aims of subsea pipeline flooding are to:

• Reduce the size of vessel required for pre-commissioning
• Negate the need for the vessel to remain on station during the bulk of the operations
• Remove the need for an expensive down-line, which is prone to damage
• Reduce schedule by increasing possible pig speed
• Reduce schedule by use of seabed water removing thermal stabilization for hydrotest
• Reduce crew size, equipment spread size, and environmental impact by removal of diesel engines on pumps, and also to improve safety by taking operations off-deck.

Offshore vessel requirements

RFM loading arm stabbed in.

In the following, we look at the commercial drivers for using such a system. For example, experience suggests that we need to inject 3,420 lpm (903 gpm) of filtered, treated seawater into a pipeline at a water depth of 1,000 m. Looking for example at flooding a 8-km (5-mi), 16-in. line at 1,000 m (3,281 ft) water depth, we can draw the following conclusions:

• The down-line option requires almost 10 times the deck space of the RFM option – with the current shortage of DP vessels and with vessel rates of around $40,000 per day, this can have a major impact on project cost.
• As the RFM floods the line with ambient temperature water, there is no stabilization period – this could save two days.
• The deployment and recovery time for the RFM is far quicker than for a 4-in. down-line.

ROV operating RFM.

As with all new technologies, there are circumstances where the RFM may not be suited to a deepwater project. These include:

• Where one or both ends of the line terminate at a platform/FPSO, as with SCRs
• Where a down-line will be deployed for other operations and can conveniently be used for flooding
• Where a large number of pigs are used
• Where the line has to be flooded with either fresh water or MEG
• Where one on of the line terminates in shallow water.

Subsea pigging equipment

The original subsea pigging unit was designed by pre-commissioning engineers with little input from ROV and subsea specialists (despite efforts to include them). While the device was successful in achieving its pre-commissioning objectives, it was not the optimum method of operation for the ROV or deployment vessel. Unwieldy HP flexible jumper hoses, relatively crude instrumentation, and new ways to use choke assemblies meant there were areas to improve. With this in mind, recent improvements on the RFM included:

• Holding more chemical than the original subsea unit, allowing less recovery and deployment cycles and use on longer and larger lines
• Using rigid loading arm technology to reduce subsea connection times and to reduce the risk of HP flexible jumper hose damage
• Being extremely ROV friendly – ROV specialists were involved in design to ensure minimum ROV interface issues.

Other improved features include:

• An on-board latching mechanism that allows fast ROV connection for boost pumping
• An on-board emergency release system means no risk of an ROV getting stuck on the RFM
• Advances in electronics mean more reliable instrumentation
• Deployment times are less than one hour in deepwater.

Subsea hydrotesting unit

Recent developments in subsea pumping systems have allowed ROV pump skids to carry out subsea hydrotesting and leak testing of pipeline systems, thus affording additional savings on vessel size and cost. When used in with the RFM, significant benefits can be achieved. Naturally, the systems that can be tested are limited by the maximum performance available from an ROV test pump skid. The BHI SHP (subsea hydrotesting unit) can produce over 40 lpm (10.5 gpm) pressurization rate from typical project ROVs.

Subsea hydrotesting unit.

Previously, we examined a down-line system that was needed to flood an 8-km, 16-in. line. Deepwater lines typically require hydrostatic testing at between 200 barg and 350 barg. A typical 4-in. downline would not be rated for such pressures (specialized down-lines that can handle such pressures often cost too much for such applications). Thus, a different down-line must be deployed to pressurize the line. Deployment times for the down-line are similar to those of the flooding down-line.

The SHP can be deployed with the RFM boost pump; hence there is no delay between completion of flooding and commencement of pressurization. It has been estimated that this saves a minimum of 24 hours per pipeline.

Smartgauge technology

We need to examine the gauging of the line. All offshore pipeline pre-commissioning operations include the proving of the internal bore of the line. This is achieved normally by fitting a segmented aluminum disk to one of the filling pigs, the disk having an outside diameter equal to between 95% and 97% of the minimum pipeline internal diameter. The principle is that any restriction in the line (buckle, dent, etc.) would cause one of the aluminum "petals" to bend, indicating a restriction in the line.

Gauge pig prior to launch

The gauge pig is then run as part of the pipeline filling pig train and most specifications require that the gauge plate be inspected visually prior to the hydrotest. This ensures there is no mechanical damage within the line that could be affected by the hydrostatic test.

Removing and inspecting the gauge plate is simple onshore (and for pipelines with above surface terminations); but requires additional work on pipelines terminating subsea and in deepwater. It was for this application that BJ developed the Smartgauge tool to meet the following needs of deepwater pipelines. This technology:

• Allows lines with restrictions (heavy wall bends, PLET hub restrictions, reduced bore valves) to be gauged.
• Permits gauging data to be reviewed and analyzed. This helps users pinpoint and identify any restrictions.
• Incorporates a system to remotely annunciate the result of the gauging run. This means that the hydrotest can start immediately upon completion of flooding without the need to recover the gauge plate to surface for visual inspection.

A standard mechanical gauge plate gives no indication of where damage occurred; this makes identification of location difficult, time consuming, and expensive. By using the multi-channel Smartgauge tool with a segmented flexible gauge plate, both the clock position and the location of multiple defects can be ascertained, reducing the time needed to find the problem.

Future developments

Improving ROV capabilities and advances in electronics will benefit remote flooding and pigging systems. Use of remote data transmission and signaling will allow associated tasks to be reduced in impact and cost, or taken completely off of project critical paths.

All future developments will be driven by these common objectives:

• Reduce the in-field time required to complete subsea pre-commissioning, hence saving on both the vessel costs and hire periods for pre-commissioning spreads.
• Remove or replace operational processes that have high risk (such as deployment of large diameter down-lines in deepwater).
• Minimize offshore vessel deck space for pre-commissioning equipment, allowing smaller and cheaper vessels to be used.

John Grover
Baker Hughes Process and Pipeline Services

Long-Term Outlook for Gas Remains Bullish

Despite the shift by producers towards oil-focused drilling away from natural gas, the long-term outlook for U.S. natural gas demand remains bullish as U.S. nuclear power and coal plants are retired and gas-fired electricity use rises over the next few years, said Pearce Hammond, director of institutional research at Simmons & Co. International, at Platts' sixth annual Oil & Gas Shale Developer conference in Houston this week.

The anticipated retirement of nuclear power plants could potentially add 1 Bcf/d of gas demand by 2020, and the expected retirement through 2020 of 50-60 gigawatts of U.S. coal generation assets could add 4 Bcf/d of additional U.S. gas demand. LNG exports from the U.S. could add an additional 2 Bcf/d of U.S. gas demand, Hammond said.
Increased future use of natural gas vehicles in the U.S. could also create additional 1 Bcf/d of demand for U.S. gas, and gradual growth in industrial demand could add another 2 Bcf/d.

While the U.S. has lost ground to Asia in terms of industrial base, the U.S. has the demographic advantage versus China, whose population is aging and growth limited by the nation's one child policy. Manufacturing costs also have begun rising in China, along with wage rates, and the availability of cheap energy resources at home has prompted some companies to bring manufacturing operations back to the U.S.

U.S. gas demand for 2011 is estimated at 67 Bcf/d, up from 66 Bcf/d in 2010, but less than U.S. supply estimate of 68.4 Bcf/d. Still, the supply overhang estimate is less than previous estimates, thanks in part to cold weather earlier this year which boosted gas demand for heat generation, Hammond said.

Given high oil prices, the Eagle Ford oil shale play in South Texas and the Permian Basin in West Texas and eastern New Mexico remain hot spots for drilling activity. However, activity in the Marcellus shale gas play continues to hold up despite the capital flow shift from gas into liquids.

Unconventional natural gas, particularly shale gas, will make an important contribution to future U.S. energy supply and carbon dioxide emission-reduction efforts, according to The Future of Natural Gas, the fourth in a series of MIT multidisciplinary reports examining various energy sources and their role in meeting future demand.

Demand for natural gas, which burns cleanly and efficiently with very few non-carbon emissions, will likely grow in the U.S. and worldwide for use in power generation, industrial, commercial and residential sectors due to its abundant availability, utility and low cost compared to other energy resources. Gas can play a major role in reducing greenhouse gas reduction, and "play a critical role as a bridge to a low-carbon future," according to the MIT report, which was released earlier this month.

The ample domestic supply of gas has stimulated interest in its use in transportation, driven by the oil-gas price spread and opportunity to lessen oil dependence in favor of domestically supplied fuel, including natural gas-derived liquid fuels with modest changes in vehicle and/or infrastructure requirements and reduce carbon dioxide emissions in direct of gas.

Compressed natural gas (CNG) offers a significant opportunity in U.S. heavy-duty vehicles used for short-range operation, such as buses and garbage trucks, where payback times are around three years or less and infrastructure issues do not impede development. However, for lighter passenger vehicles, even at 2010 oil-gas price differentials, high incremental costs of CNG vehicles lead to long pay back times for the average driver.

Payback periods could be reduced significantly if the cost of conversion from gas to CNG could be reduced to levels experienced in other parts of the world such as Europe.

The current supply outlook for gas will contribute to greater competitiveness of U.S. manufacturing, while the use of more efficient technologies could offset demand increases and provide cost-effective compliance with emerging environmental requirements.

The growing global interest in developing shale gas resources presents the U.S. energy industry with an opportunity to only build up a supply chain of exports for rigs and equipment, and an opportunity to support international allies, Melanie Kenderdine, executive director of the MIT Energy Initiative, told conference attendees. Providing aid in developing shale gas resources in southern South America can help counterbalance against the Chavez regime in Venezuela or help stabilize economies and governments in Africa and the Middle East.

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Crude Drops on IEA's Surprise Move

Crude prices plummeted to a four-month low Thursday after the International Energy Agency (IEA) said it would release an emergency oil supply to alleviate high prices.

In an attempt to offset the supply disruption caused by Libya's civil war, the IEA said it will release 60 million barrels of oil over a 30-day period. Its members will release 2 million barrels of oil per day (bpd). Half of the amount will be provided by the U.S. Strategic Petroleum Reserve, which currently stores 727 million barrels of crude.

The IEA last tapped emergency resources in September 2005 after Hurricane Katrina disrupted production on the U.S. Gulf Coast.

Light, sweet crude lost $4.39 Thursday, settling at $91.02 a barrel. Prices traded as low as $89.69 and peaked at $94.47. Meanwhile, Brent crude ended Thursday's session at $107.26 a barrel, down $6.95. Goldman Sachs claims IEA's surprise release could cause Brent prices to decrease by $10-$12 a barrel by the end of July.

Likewise, natural gas for July delivery settled lower at $4.193 per thousand cubic feet. The drop came on government reports showing an increase in U.S. inventories. The U.S. Energy Information Administration (EIA) said stockpiles grew by 98 billion cubic feet last week. This marks the year's second-largest increase in U.S. natural gas inventories.

The intraday range for natural gas was $4.15 to $4.34 Thursday.

Front-month gasoline futures settled down 13.57 cents at $2.84 a gallon. Prices fluctuated between $2.785 and $2.955 a gallon.

Get Ready for a Natural Gas Boom

Source: George Mack of The Energy Report  (6/23/11)

Schachter Asset Management Analyst and Investment Advisor Josef Schachter, who provides oil and gas research to Maison Placement Canada clients, is recommending a group of Canadian companies that are maintaining the delicate balance between oil, on which he is bearish, and natural gas, which he believes will soon enrich both producers and investors. In this exclusive interview with The Energy Report, Josef shares some value-priced names he feels are poised for big gains, along with natural gas' rising price.

Companies Mentioned: Dana Gas PJSC Delphi Energy Corp. Encana Corporation Galleon Energy Inc. Imperial Oil Ltd. Niko Resources Ltd. Questerre Energy Corporation Sea Dragon Energy Inc. Sterling Resources Ltd. Suncor Energy Inc. Talisman Energy Inc. Vero Energy Inc. WesternZagros Resources Ltd.

The Energy Report: You recently said that if gasoline prices continue to rise we should see West Texas Intermediate (WTI) oil in the low-$70s in the third through fourth quarters of 2011 (Q311–Q411). That represents an approximate 25% decline from current levels. Does that mean that the North American economy will be in trouble?

Josef Schachter: That's the key. When you get $4/gal. gasoline at the pump, or $1.25–$1.35/liter in Canada, you start seeing demand destruction. If we look at the weekly Energy Information Administration (EIA) data for the week ending June 3, we can see that demand for finished motor gasoline was 9.16 million barrels (Mbbl.)—down 268,000 barrels on the week. And year-to-date (YTD), it's down 0.3% to 8.956 Mbbl. per week. So, we're already seeing demand destruction in the States from the handle of $4/gal. In Canada, we're seeing the same thing; and Europe, of course, is showing much weaker demand. Japan also is showing much weaker demand, and we have the tightening of credit in China. Quantitative easing 2 (QE2) is now out of the way, so the stimulus is gone in the U.S.

There is probably a $30/bbl premium in the price of WTI oil, and 50% of that relates to Middle East issues with about 900,000 barrels per day (bpd) that have been cut off from Libya. If we see the Libya issue resolved in the next three to six months with Muammar Gaddafi going out, that production will come back on and will remove the pressure of the Arab Spring premium. The other 50% is the hedge and commodity funds.

If we see weakness in the economy, the whole commodity board will come down and we'll see the U.S. dollar rally. We believe oil prices will lose that $15/bbl premium held by speculators in commodities and exchange traded funds (ETFs). The combination of the two could take $30 off the price of WTI oil, which is just around $93.40 today. Remember, when you have weak economic conditions, you trade below fair value. Recall Q109, while the fair value price might have been $50 for oil, we traded in the low-$30s.

TER: You use technical analysis quite extensively in your research reports, more than many sellside analysts. What are the charts telling you?

JS: My background is fundamental. I have an accounting background and am a Chartered Financial Analyst (CFA), so I come at it from a fundamental point of view. But I have had healthy respect and training from the technicians during my +30 years in the business, so I do look at the charts. We were at $112/bbl of WTI, now we're at $98—and $94 is not that far away. If we break $94 on the charts, then it's going down and looks like low-$70s. So, I think you must have respect for, and use all of, the disciplines. But I come at it from a supply/demand point of view; and, while the price of oil ran to $112 due to concerns about supply removal in the Middle East, that could be reversed if Libyan production comes back on because it's a big producer.

TER: With $4/gal. gasoline, we've seen oil demand falling in the U.S. But what about natural gas, isn't the reverse true? At the $4–$5 per-thousand-cubic-foot (Mcf) level, shouldn't we be using a lot more gas? Isn't that equivalent to about $1/gal. gasoline?

JS: Yes, we could see natural gas prices triple and still be the fuel of choice. The inventory picture has been high, but that's coming down. Because of the Haynesville and the Marcellus and everything else, there was a perception that we have a natural-gas glut. We believe natural gas prices will go significantly above $5/Tcf this summer with big air-conditioning demand during the hurricane season. Over the winter of 2011–2012, we think NYMEX gas will trade north of $7/Mcf.

TER: Nat gas is quite a bit higher in Europe and Asia. Is there an arbitrage opportunity?

JS: There is currently no arbitrage capability, in terms of shipping natural gas from the United States to Europe or Asia. Remember, there are costs to do that. If prices in Japan are $10 or $12/Mcf and today we're trading at $4.35/Mcf for NYMEX July, there's an arbitrage there; but there are landed costs in building a facility. Cheniere Energy Partners L.P. (NYSE.A:CQP) and other companies are talking about this. It may cost $5/Mcf more to convert that into liquefied natural gas (LNG) and ship it to Japan due to distance, and it may not be enough of an arbitrage to attract the kind of capital needed.

TER: You're bullish on natural gas and bearish on oil. Do you feel like gas prices will rise at the expense of oil, with investable dollars being redeployed into gas and gas stocks?

JS: That's what we've been recommending to Maison's institutional clients. If you look at some of the big-name oily stocks, they've already come down a bit from where they were. For instance, Suncor Energy Inc. (TSX.V:SU; NYSE:SU) was trading at $47 in February, and now it's trading at $38. So, there's been a bit of a haircut there. The big Canadian producer Imperial Oil Ltd. (TSX:IMO; NYSE.A:IMO) was $54 in February, when WTI oil was at $112/bbl, and now the stock is trading at $44.56.

So, we've already seen a correction in the oil names, and we think that will continue, especially if we see another $20–$30/bbl come off the price of oil. Gas stocks have done the reverse. At the beginning of the year, Encana Corp.(TSX:ECA; NYSE:ECA) was a $29 stock, and now it's a $31 stock. That's not a big move, but it's gone up versus the oily names going down.

TER: Back in March, the Government of Quebec halted shale gas drilling until a safety evaluation could be completed. This could take up to two years and, with court challenges and environmentalists converging on this area as a battleground, it might take longer. What's your feeling on this?

JS: There's a pilot phase that will go on for the next two years. I believe six wells are forecast, two of which are being worked by a joint venture (JV) between Talisman Energy Inc. (TSX:TLM) and Questerre Energy Corp. (TSX:QEC). They're going to be monitored by the government, which will have people onsite. What the companies will have to do is deal with local people and environmentalists, get approval from the farmers and explain what's going on. They're going to measure the methane before and after they start drilling since the companies want to prove that they're not increasing the amount of methane from their activity. So, the industry has to prove its environmental case.

Quebec has a history of environmental legislation for mines; but in the end, it does approve the mines if they go through the environmental hurdles. I think the case will be the same here with natural gas. Companies might not be able to drill close to Montreal or Quebec City, but that's the same issue with New York. However, in our minds, there will be activity; it's just a question of when it happens. Remember also, there's an election in Quebec in two years; and I believe the government wants to wait until after the election on this issue. So, it's going to take that two-year window or more.

TER: What are the plays that you're recommending for investors today?

JS: We like companies in Western Canada, where there are multizone liquids-rich natural gas areas. Oil is in some of the plays like the Cardium Formation or the Doe Creek. So, we like companies like Delphi Energy Corp. (TSX:DEE), Vero Energy Inc. (TSX:VRO) and Galleon Energy Inc. (TSX:GO). We also like some Canadian-domiciled companies dealing with international markets like Niko Resources Ltd. (TSX:NKO), which is in India, Indonesia, Kurdistan, Trinidad, Madagascar and a number of other places.

In the past, we've been fans of Sterling Resources Ltd. (TSX.V:SLG), which is in the North Sea, the Netherlands and offshore Romania; however, currently we are on the sidelines due to their ongoing difficulties in Romania. We like WesternZagros Resources Ltd. (TSX.V:WZR), which has just completed a very exciting well, Sarqala-1, in the Kurdistan region of Iraq and will spud another well, called Mil Qasim-1, in July. We like a company in Egypt, called Sea Dragon Energy Inc. (TSX.V:SDX). It has the same management team that was successful with Centurion Energy International Inc., which was acquired by Dana Gas PJSC (ADX:DANA) in 2007. A lot of Canadian-domiciled companies are taking the modern technologies around the world and are doing very well with that.

TER: You mentioned Delphi and WesternZagros, which are your top-two picks. One thing that jumps out at me is that neither of these companies has had spectacular returns. So, is this your contrarian gas play?

JS: Yes. DEE got hurt because of their gas bias, but they always had land with liquids-rich capability. For example, in 2009, Delphi was producing about 15% oil and 85% natural gas. This year, it's going to do about 27% oil and liquids—and that number will go north of 30% by the end of the year. It's going to generate over 50% of its revenue from oil and liquids; so cash flow will go up, and production volumes will go from 6,700 boe/d in Q109 to north of 9,500 boe/d by year-end. Delphi is doing the right things, in terms of the mix. It's going after the liquids-rich capabilities on its land, but the company always has the dry gas sitting in its inventory; so, when gas prices go back to $7–$8/Mcf, Delphi can move those assets. In the meantime, it can increase its net asset value (NAV) and cash flow by going after the liquids. It's similar to the gold business—when prices are low, you go after your best veins; and when prices are high, you go after your bad veins.

TER: Your target price on Delphi is $4, which implies a 60%–65% return, but I noticed the company's NAV is $3.78. It sounds like a very conservative target price.

JS: Yes. And that's because we're looking for Delphi to trade at a ratio of its cash flows, and we're looking at it annualizing about $0.60 in cash flow by Q411. The cash flow multiple should be no greater than the proven reserve life index (RLI); and, if you have seven-and-one-half years of proven reserves, you also have probable and possible reserves, tax pools and land value to protect the value for shareholders.

So, we take an approach in which a company's maximum cash flow multiple should be equal to its proven RLI. However, we didn't even use that in this case. So, you could argue that we may have an even higher target, but our view is to use a reasonable target that we can see makes sense. Then, if it gets to that target and the company is doing better than expected, we can always review it again and come up with a new target.

TER: Your other top pick was WesternZagros, on which you have a target price of $1.50. That represents a roughly 175% return. What are the risks here?

JS: Well, this is in Kurdistan and now the Baghdad and Kurdistan governments are getting their collective act together, in terms of allowing money to be paid to the players in the area, which makes a lot of sense to us. WesternZagros has a lot of cash on the balance sheet, so it has enough for the next phase of drilling. What we like about the company is that the Sarqala-1 well has tested at 9,444 bpd light, +40-degree oil. So, it may have a massive oil field there. WesternZagros' biggest shareholders are George Soros and John Paulson. Thus, we have big, international investors that believe this company has a big land spread, very attractive base and has proven that there is light oil on it.

TER: You went to the SEPAC Oil & Gas Investor Showcase in Calgary at the end of May. What was the atmosphere there? What did you hear?

JS: If a company is in natural gas only, it's not generating a lot of cash flow and not making any money. And if it has any debt, it has problems. So, almost every company was trying to draw attention to itself saying, "Let's find the liquids-rich or oily stuff and use the new technologies to harvest our lands." Nearly every company was carrying the flag of "liquids-oily" to draw attention.

From my perspective, they're doing what they have to do in these tough times. But it is getting easier. The basin in Western Canada is gassier, with small pools where the new technologies will help with the oil recovery. But in the long run, we're going to need a much higher natural gas price for the industry to be successful—not only to get a cash flow but also to start generating free cash flow and net income. That's when people can see that it's not just trading dollars in the industry, but also making real money.

TER: Can the small guys survive?

JS: Again, they've got to go get land where the big boys aren't pushing up prices exorbitantly. That means they will have to go into areas that are not 'hot.' Everybody loves the Duvernay or the Cardium, but land prices are rising above $5,000/acre. A little company can't do that today. So, it must have had the land in inventory that it holds or has farmed in from a big boy. But the key thing is that the company will have to be away from where the big boys are located. Companies like Delphi, Galleon and Vero were buying low-priced land in these hot areas before the big boys come in—and where the little guys now just can't compete.

TER: That makes sense. Josef, do you have any further thoughts that you'd like to leave with our readers?

JS: Just that we're cautious right now with QE2 over and with all the country risks in Europe. I think almost everybody agrees that Greece has problems that cannot be fixed. At some point, it will have to face the moment and resolve these issues with haircuts everywhere, which is deflationary. So, if that's the case, and we have a weaker U.S. economy along with Europe, China and Japan, we think there's a chance for a severe correction. So, we're not saying investors should go out and buy things right away, but rather build up their buy lists.

Sometime this fall, the market could have a 10%, or even 30%, correction. I'm not sure which one it will be; it depends upon how serious the problems in Europe become. And, of course, Americans are facing their debt issues. So, if we do see a severe 30% correction, some stocks could go down much more than that; so, you want to be ready to be a buyer. We're saying if you have oily names right now, sell them and lighten up your exposure. If you have to be exposed to energy, be in the natural gas-focused names, but sit there with some decent cash reserves underweighting the sector and be ready to be a buyer sometime this fall when the pain is over.

TER: Great advice. Thank you, Josef.

JS: Thank you.

After a successful investment stewardship at Richardson Greenshields of Canada Limited (RGCL), and the Royal Bank purchase of that firm, Josef set up his own investment advisory business, Schachter Asset Management Inc. (SAMI) in late 1996. Mr. Schachter has nearly 40 years of experience in the Canadian investment management industry. He was the market strategist and director at Richardson Greenshields, as well as a member of its Investment Policy Committee. He holds the Chartered Financial Analyst designation and is a past chairman of the Canadian Council of Financial Analysts.

Currently, Mr. Schachter and his research team provide oil and gas research coverage to the institutional clients of Maison Placements Canada and presents to, and consults, various industry companies and organizations. Mr. Schachter is a frequent guest on BNN and is regularly quoted in such news and financial publications as the Globe and Mail, National Post and Business Edge—the latter of which awarded Mr. Schachter its "Stock Picker of the Year" award in 2003, 2004 and 2007. He is also a regular on various radio shows including Michael Campbell's "Money Talks."

Want to read more exclusive Energy Report interviews like this? Sign up for our free e-newsletter, and you'll learn when new articles have been published. To see a list of recent interviews with industry analysts and commentators, visit our Exclusive Interviews page.

DISCLOSURE:
1) George Mack of The Energy Report conducted this interview. He personally and/or his family own shares of the following companies mentioned in this interview: None.
2) The following companies mentioned in the interview are sponsors of The Energy Report: None.
3) Josef Schachter: I personally and/or my family own shares of the following companies mentioned in this interview: WesternZagros Resources and Delphi Energy Corp. I personally and/or my family am paid by the following companies mentioned in this interview: None.

The Outlook for Natural Gas

Timing is everything in the market, and being able to spot trends is critical to locking in attractive returns. Natural gas producers have taken a beating over the past three years, but there are encouraging signs that natural gas might be ready for a break to the upside. Despite a seasonably weaker shoulder season, NYMEX prices are inching above 10-month highs and observers are finally buying into the idea that stronger prices are around the corner.

Longer-Term Outlook Expected to Strengthen
The International Energy Agency (IEA) said this week that natural gas is about to enter a "golden age" with worldwide gas use to increase by 50% by 2035. That might seem far away, but the immediate present also has been encouraging of late. Calgary-based Energy Economist Peter Tertzakian is now predicting declines in existing production will trump new production adds from the big new shale plays, driving prices higher. All the while, U.S. industrial demand growth is the highest in a decade, according to the Energy Information Agency (EIA). Add some hot weather in big consuming markets, and we've seen a nice steady rise since May.

The Contrarian View: Buy Low, Sell High
Already we're starting to see some movement on analyst price forecasts.

FirstEnergy is a boutique brokerage firm in Calgary specializing in oil and gas. Analyst Martin King said Tuesday that a longer-term average gas price of $5.50 is "reasonable" heading into 2012, although his own 2011 forecast still calls for an average of $4 for the year.

The difference between the two numbers sums up the opportunity in a nutshell—almost 30% on price alone. It's not unreasonable to expect stocks to follow suit with higher multiples and valuations.

Unfortunately, the pure-play gas producer has become an endangered species and it's hard to find a lot of names with growing production exposed to rising spot prices.

The Gas Train Wreck Survivors: Lean and Mean
The good news is that the producers that managed to stick around over the past three years are bonafide survivors. They've taken a beating and still managed to be profitable through the downcycle. In fact, many have thrived and have quietly posted nice share price appreciation. (See our story on the Surprise Junior Stock Performers)

Although some, like Birchcliff Energy (TSX:BIR), are near 52-week highs, there could be even bigger upside around the corner. In fact, there WILL be more upside with higher gas prices. The company has been furiously developing its Montney play in Alberta and says it can still make money at a nat gas price of $3/MMcf. The company has posted positive earnings for nine consecutive quarters and has all of its production unhedged to sell into a rising market. It's spending more than $260 million this year to double its processing capability, which will give the company room to ramp-up volumes.

Peyto Exploration's (TSX:PEY) been in the wilderness forever it seems, but it's also testing year highs. Both companies have made solid share-price gains; Peyto alone has quadrupled since the 2009 market low.

Crocotta Energy (TSX:CTA) is another survivor that was forced to sell assets and recap the company in September of 2009. Since then, its share price has doubled while it works liquids-rich gas near Edson in central Alberta. Liquids are in big demand in the heavy oil patch and amounted to almost one-third of Crocotta's Q1 production. Notably, Tourmaline (TSX:TOU), which just bought out Cinch Energy (TSX:CNH), is just to the west of it.

Advantage Oil and Gas (TSX:AAV) posted a small loss of three cents in Q1, which wasn't bad considering it spun off its oil assets to focus on its core Montney development. It has 28 million cubic feet a day hedged at Canadian prices of $6.25 per gigajoule (GJ), which will protect the balance sheet until a full-blown recovery takes hold.

Longer-Term Exports Hold Promise
Looking even longer term, big players, such as Encana, Apache and EOG are looking at exporting liquefied natural gas (LNG) off the West Coast of Canada.

Natural gas prices in Asia are about double what they are in North America, and even after shipping costs producers will be making a lot more money selling gas in Asia. But smaller players have bought in, as well. Earlier this month Progress Energy (TSX:PRQ) teamed up with a Malaysian company, Petronas, one of the world's largest LNG companies, to develop unconventional gas and build a second LNG export terminal in BC.

These are huge multibillion-dollar investments, and the risk is all going to be project execution and raising enough money to stay in the game. Having a huge multinational for a partner is a huge plus in that regard, but this is definitely a five-year payback. Patience is the key here, but this suggests things are looking better in a previously dead-end sector with nowhere to go but down. Six months ago, few, if any, analysts' gas prices would be close to $5/MMcf in North America—almost everybody was predicting lower prices. It remains to be seen if this is a sustainable recovery for producers and their investors. Timing and finding ways to profit from a rebound will be the test.

Keith Schaefer
Oil & Gas Investments Bulletin

June OG&PE

The June 2011 issue of Oil, Gas & Petrochem Equipment is available to view or download.
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The Well Completions Bottleneck

At the height of the 2008 commodity price surge for both oil and natural gas, the inventory of wells drilled but not completed was also tracking above the norm at over 2,000 wells. A primary factor contributing to this backlog was contractual as operators drilled in order to hold their leases in some instances. Additionally, in some regions a shortage of labor and equipment was exacerbating the situation.

But as the rig count proceeded to drop at an unprecedented rate during the later half of 2008, the industry was then able to work through the backlog over the ensuing months. An unintended consequence was that, as operators worked through their excessive inventories of uncompleted wells, natural gas production climbed while the natural gas rig count fell dramatically. The saying "History never repeats but it sure does rhyme," applies well to this scenario. But this time around the trends point to U.S. oil instead of natural gas experiencing production increases when the rig count eventually slows.

According to Halliburton, the number of uncompleted wells in the United States was approaching 3,500 wells at the end of 1Q11. Given that the type of drilling underway has changed dramatically over the last four years (with horizontal drilling now comprising a significant portion of the mix) and the high rig count in general, we anticipate that the backlog for completions will continue to grow (as long as drilling continues to be undertaken at a faster pace than capital expansion by oilfield service providers). The relevance of this situation is even greater when you consider that the service intensity necessary to complete wells has doubled what it was on average two years ago.

As of the most recent count there were approximately 1,800 land rigs drilling in the lower 48 states for oil and gas. If you assume that each frac crew can complete six wells in the average time it takes to drill one well, then the equilibrium point for the number of frac crews in the lower-48 would be the number of horizontal and directional rigs drilling in US divided by 6.

Recent estimates peg the total horse power (hp) across North America available for stimulating wells at approximately 9 to 10 million. If you consider that between 25k to 40k hp is needed to stimulate each horizontal shale well, then that places the total number of frac crews covering North America somewhere in the neighborhood of 300 crews. Backing out a healthy figure for what are likely Canadian crews implies that there are at least 200 fracing crews available to complete wells in the US. Thus, as long as the unconventional count is over 1,200 rigs, then we would anticipate that the backlog for completions would continue to grow.

Currently there are approximately 1,300 rigs drilling unconventionally. This would suggest that the current back log will continue to grow by 100 uncompleted wells per month. At this pace the backlog could top 4,000 wells before the start of calendar 2012. What is different about this build up compared to 2008 is that the composition of wells favors oil, condenstates, and NGLs. If you assume that the composition mirrors the rig mix, then over half the uncompleted wells will eventually produce oil.

During 2009 there were over 363,000 wells that produced nearly 1.7 billion barrels of crude in the lower 48 states. That equates to about about 12 barrels per day per well. However, you have to remember that over 2/3 of the existing oil wells are producing at marginal rates. So, using a higher average production of 200 bpd per uncompleted oil well would imply 400,000 barrels per day of production (~2,000 uncompleted oil wells x 200 bpd) untapped at the end of 2011. To put this in perspective, 400,000 bpd of oil would raise current U.S. production of 5.6 million bpd by 7 percent.

The implications of these trends points to a continude rise in prices for fracturing services and supplies. Current estimates place the amount of water used to fracture a well at 4,000,000 million gallons. Proppants (sand or ceramic) used hold the fissures open weigh approximately 5,000,000 lbs. per well. Usage of both is likely to continue rising considering that both the number of frac stages and the lateral lengths drilled are increasing. While there are several items going down the well during the hydraulic fracturing process, the largest component of the mix is definitely water.

VIEW FULL CHART

We mentioned that the service intensity has increased over the past two to three years. Bilateral wells, zipper-fracs, and longer laterals with more stages/production zones are all contributing to the increased requirements for both equipment and materials.

Keeping this growth in mind, we have provided an estimate of the largest pressure pumping providers across North America in 2011. Halliburton leads the oil services industry possessing one-fifth of all North American pressure pumping horsepower. And even though the industry is speckled with a multitude of small operators, we note that Spears estimates that nine firms control approximately 80% of the North American market. The smallest of the top nine is Patterson-UTI, which increased its pressure pumping capacity with the purchase of Key Energy's well stimulation business last year.

by  Trey Cowan

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Wednesday, June 22, 2011