Is the Oil Market Getting Hoodwinked?

By
Keith Schaefer
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Is the energy sector under-reporting oil demand?  Some recent research suggests that’s possible—potentially by a lot—as in 1.2 million barrels of oil per day (bopd).

For oil bulls, that’s not enough right now to sway oil prices.  But it could mean the market is tighter than everyone thinks.

And that wouldn’t be hard, as incredulous as it may sound.  I mean, both supply and demand are well over 90 million bopd in the world now.  1.2 million bopd isn’t that much put into that context.

ARC Financial Chief Energy Economist Peter Tertzakian highlighted in his 2005 book–A Thousand Barrels a Second—that the world really was consuming 1,000 barrels a second (!) of oil, which translated into 86.4 million bopd.

Now The International Energy Agency (IEA–they’re based in Paris France) ) says demand has since increased to 92.5 million bpd of oil in 2014, while oil supply reached a record 93.6 million bopd.

And according to the most recent data both supply and demand for oil increased again in Q1 2015, with oil demand growing to 93.1 million bopd and supply expanding to 95.1 bopd. These statistics clearly outline a 2 million bopd oil surplus.

A surplus of oil is evident from the decline in prices.  But there is some interesting evidence that these excess supply statistics may be too pessimistic. Or as Mark Twain once observed, “Facts are stubborn things, but statistics are pliable.”

What if this 2 million barrel a day surplus does not in fact exist?

What if demand is actually greater than estimated and the world’s supply and demand of oil is actually much more in balance than these statistics indicate?  It would help explain the 50% increase of prices from the lows reached earlier this year.

With almost 100 million barrels a day being produced to fuel our planes, trains and automobiles (as well as into all sorts of manufactured goods and plastics) it is impossible to accurately track where all this oil is sloshing around.

How much oil is actually being illegally exported from Iran? How much is OPEC actually breaking their own quotas? How much is Russia or other oligarchs fudging official numbers for personal benefit.

And that is just on the supply side.  How do you even begin to track the demand of oil? “Quick honey, call the IEA, I just drove the kids to hockey!”

In two June 2015 reports, Marshall Adkins and his energy team at the US arm of securities firm Raymond James looked at these statistics and came to some very interesting–and bullish–implications for future oil prices.

For the IEA’s numbers to work and make sense, the global supply and demand must add up to changes in inventory. If supply is 2 million bopd greater than demand, then inventories should be going up by that same amount. But what happens when these numbers don’t balance out?

In fact, these numbers almost never add up.

And the IEA statisticians do what all great statisticians and accounts do, they create a “plug” line to balance out the difference. In the United States, the EIA does the same thing, and calls this the “miscellaneous to balance” (MTB), and is what makes the numbers balance.

And in the first quarter this plug number totaled 1.2 million bpd, or 60% of the 2 million bpd of oversupply estimated by the IEA. And to put this in perspective, this is equivalent to the UK’s daily oil usage.  So maybe, just maybe, our surplus isn’t as great as is being reported.

Over the past 15 years, the IEA’s MTB plug number has averaged NEGATIVE 100,000 barrels, compared to positive 700,000 barrels in 2014 and 1.2 million in the first quarter of this year. The most recent numbers are substantially different from historical averages, which leads us to suspect that some isn’t quite adding up.

1

And just like other economic data, the IEA’s data gets continually revised as more and better data comes in. In fact over the past 15 years, the IEA revised upward their annual demand estimates by an average of 700,000 bpd.

So given that the current MTB estimate is much greater than the historical average and that the MTB is typically revised by 700,000 bpd, there appears to be a very good likelihood that demand will be revised higher in coming quarters.

2

And in other ways their data seems curiously inaccurate. Yes Europe and Asia are having their challenges, but in 2014 the IEA reported that global oil demand only increased by only 700,000 bopd (or 0.75%). And this seems exceptionally low given that global GDP increased by over 3% in 2014 and that oil demand typically increases when prices drop as significantly as they did last year.

Barring any significant revisions to the supply side of the equation, it appears that demand could be revised from being oversupplied by 600,000 bopd to 300,000 bopd oversupplied in 2014.

And for 2015, the current 1.2 million bpd is expected to be revised downward to a much more reasonable 300,000 bpd of oversupply.

In the U.S., the EIA has also seen their plug number reverse course in 2015: Says Raymond James on June 29:

“…we think the overstated weekly U.S. oil supply is actually being captured by a recent major change in the EIA “plug” number…Since March, the EIA balancing plug has totally reversed, suggesting overstated U.S. oil supply during the second quarter of 2015. The weekly adjustment figure (or EIA plug) has undergone a shocking transformation over the past several months. Specifically, the adjustment in the weekly inventory report has plunged from a positive 362,000 bpd in 1Q15 down to a negative 113,000 bpd in June. So what happens if we assume that the “unaccounted-for oil” plug is really U.S. lower-48 supply?..”

Here’s how Raymond James’ proprietary model is suggesting oil production is moving:

3

This would indicate the world’s oil market is much tighter than many investors now think.  Psychology is going completely the other way right now, so these data points will get ignored–until they don’t.

-Keith

Leverage Comes in Different Forms—Run From This One

By
Keith Schaefer
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0

One of the most beaten-down names in the entire oil services sector is Paragon Offshore (PGN-NYSE). A spinoff from the deepwater-focused Noble Corp (NE-NYSE), this “standard spec” offshore driller ended its first day of regular trading at $11 on August 4, 2014.

The stock has continued on an almost uninterrupted downward trend, hitting a low close of $1.12 back in March before rebounding to a recent price of $1.69. With around 85 million shares out, that puts Paragon’s remaining equity value at a sliver of total enterprise value, which includes roughly $2 billion of debt.

This is a highly leveraged security. As regular readers know, I like leverage in various forms. I love leverage to underlying results provided by a low share count, and I often seek leverage to commodity prices (but only when I think they’re headed higher!).

Given the challenged environment for offshore drilling at current prices, Paragon certainly offers the latter in spades. It’s why I recently took a look at the stock as a potentially cheap call option on higher oil prices.

What I initially saw at Paragon was operating leverage of a $1.7 billion revenue stream and $500 million of net income on a share count of only 87 million. Plus their Q1 15 financials showed almost double The Street’s estimates of cash flow. EBITDA margins are a healthy 35-40%.

Upon closer inspection however, the financial leverage here makes PGN a time bomb with a potentially short fuse. This company is in no position to ride out a multi-year downturn in the offshore drilling space. Given the very real possibility that this is what we’ll see unfold, I just can’t get comfortable that PGN equity holders will make it to the other side of the cycle with any money left in their pockets.

I really did try to find something to like here, but the negatives are just too plentiful:

  1. Asset quality is low, with an average age of ~35 years. This leads to elevated fleet maintenance spending well in excess of “maintenance capex” in order to meet customer upgrade requirements and extend rig service lives. Management estimated over $300 million in required and discretionary fleet maintenance spending back in September.  2015 capex guidance has been cut to $200 to $220 million, with as many expenses as possible being pushed out to 2016. That would be fine if 2016 cash flow were headed higher, but it’s more likely to be cut in half or worse.

 

  1. Debt levels are high at just over $2 billion—which is only 2.4x debt-to-cash-flow—with interest expense pegged at $125 to $130 million for the year.  But after fleet maintenance, interest expense, operating expenses, and taxes, there is not much free cash flow left over to deleverage the balance sheet, if any.

US brokerage firm Wells Fargo models PGN’s free cash flow falling from over $300 million this year to a negative number in both 2016 and 2017. If PGN can’t deleverage, and its cash flow collapses as expected, that risks putting the firm offside its debt covenants next year.

Moody’s downgraded PGN’s debt ratings on June 8th, warning that debt/EBITDA could push 5x by mid-2016. It also rates the firm’s liquidity as SGL-3 or “adequate,” which is the second-lowest rating for speculative-grade issuers. This indicates that PGN only has a modest cushion to meet its cash obligations over the next 12 months.

  1. There’s a large order book of jackups being delivered over the next few years. A portion of these uncontracted rigs, especially ones coming out of unproven Chinese shipyards, are unlikely to find work, but this supply imbalance should put additional pressure on rates and utilization for standard spec jackups.

The exception here would be certain niche jobs (gas drilling, workovers) that lower-quality rigs can cost-effectively provide in places like the North Sea.

  1. PGN has outsized exposure to Petrobras and PEMEX. The former is a basket case and the latter is in disarray. These are not great customers to be depending on for contract extensions and new awards right now.

In theory (i.e. according to the balance sheet) there is asset value in the rigs that more than covers the debt, but this is a terrible market to sell into, and I don’t know who would buy this iron when they could opportunistically buy brand new, uncontracted high-spec rigs that will be hitting the market at a steady pace.

I’m all for contrarian plays, but I see very little potential for near-term fundamental improvement in the offshore drilling space, making the PGN “call option” more likely than not to expire worthless. It just seems to me that this company needs a lot to break right in order to avoid a doughnut for the equity.

The case of peer Hercules Offshore (NASDAQ: HERO) is informative here. Hercules, another highly leveraged commodity jackup operator, had the rug pulled out from under it recently by Saudi Aramco, which cut three existing contracts to $67k per day from prior dayrates of $135-137k, $117-119k, and $116-118k, respectively. This action left HERO’s cash flow gutted. Two and a half weeks later, the company announced a debt restructuring that will leave existing shareholders with 3.1% of the restructured company’s stock, plus warrants. Ouch.

EDITORS NOTE–I’ve been putting a portion of my portfolio into investments that benefit from lower oil prices–and that stock is having a great day today.  Click here to start profiting like me.

 

Are Your Energy Stocks Moving Up Right Now?

By
Keith Schaefer
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0

Which energy stocks are above their
-50 day moving average
-100 day moving average
-200 day moving average?

The answer–not too many.  But the few that are have one simple connecting thread—they are all the recognized leaders in their field.

But I try to differentiate them even further.  I own a lot of the leaders in oil and gas production, and in the services sector…and if I’m willing to hold them through this downturn, then I am much happier being paid to wait.

This company is now paying me a phenomenal 20% yield on my initial purchase from just a few years ago.

When a company increases its dividend almost every quarter for five years—that’s right, almost every quarter—that says it’s a keeper.

But even that’s not good enough for me.  Stocks have their time in the sun and then they wane.  For me to still hold a stock, it has to show me they still have a compelling value proposition for their customers and shareholders.

And one of them stands out head and shoulders above the rest in that.  One of the easiest ways this management showed they still have it—they were the only company I saw that had MORE revenue in Q1 15 than Q1 2014.

You all know what happened to oil prices.  You all know what happened to oil stocks. You all know what happened to day rates for service companies—they were amputated.

And this company skated through it all.  When is dividend increase #17 coming?  I don’t know, but I’m ready for it.

Imagine what will happen to that dividend—and the stock—when oil turns.  The Leaders always get rewarded first.

Get the name, symbol and updated report on this True Wealth Builder—right here, right now.

Keith Schaefer

 

Why EnCana’s Deep Panuke Problems Matter Part 2

By
Keith Schaefer
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0

DOES NEW ENGLAND HAVE A NATURAL GAS DILEMMA?
or….Deep Panuke Part II

By Bill Powers

Part I is here.

Natural gas discoveries in offshore Nova Scotia were supposed to help supply New England with years and years of natural gas supply.  But Exxon has already left the area (Sable Island) and Encana’s reservoirs (Deep Panuke) is watering out well ahead of schedule.

With Marcellus production now peaking, and increased pipeline capacity to the west, north and south—how will New England fare in winter months after two years of record high natural gas prices that are 3-4x the national average?

Will LNG imports make up for any shortfalls?  I don’t think so.  Despite three LNG import terminals in Massachusetts, imports have been collapsing the past few years despite extremely high prices during the winter months.

(Source: http://www.northeastgas.org/about_lng.php )  Below is a graphic displaying the trend of declining LNG into New England:

1

Why is this happening? Terminal operators can’t profitably source additional LNG cargoes on the world spot market.

Will new pipelines save New England from double-digit gas prices every winter?  I doubt it.  For example, even though an additional 2.5 bcf/d of pipeline capacity from the Marcellus to New England is scheduled to be online by the end of 2016, Marcellus gas production is set to fall for the first time in July according to the US Energy Information Administration’s (EIA) June 2015 Drilling Productivity Report.
(Source: http://oilprice.com/Energy/Natural-Gas/New-England-Growing-More-Dependent-On-Natural-Gas.html )  While I am very suspicious about most data out by the EIA, it appears they are getting the direction correct this time even though production probably began to roll over several months ago.

What about demand destruction?  Can’t New England just switch back to fuel oil in the dead of winter when natural gas prices are at their highest?  This has been tried already.  After the Polar Vortex of 2014 many utilities went into the 2014-2015 winter with extremely high levels of fuel oil knowing that they might have to find alternatives to natural gas.  However prices at the Algonquin hub still averaged over $17.00 per MMBTU in February 2015.

In fact, the demand for natural gas is becoming increasingly inelastic in New England.  With many homes and business having converted from fuel oil heating systems to natural gas in the past decade, there is an increasingly large portion of the region’s demand that will not be destroyed in the winter months no matter how high prices go.

Additionally, the closure of the Vermont Yankee nuclear plant—along with the majority of coal plants serving the region—means New England now generates approximately 50% of its electricity from natural gas.    Below is graphic produced by the EIA showing the changing make-up of power generation in New England:

2

Paper mills in New Hampshire and Maine—large consumers of natural gas but still a small percentage of the region’s overall annual consumption—shut down temporarily during the Polar vortex of 2014 due to extraordinarily high prices.  Unfortunately, New England has very few industries that can easily curtail consumption of natural gas during times of high prices or shortages.

Encana has said it will only produce Deep Panuke during the high-priced winter season.  That means Nova Scotia’s huge and fast declines in natural gas production puts New England consumers in a tough spot–with potentially chronically high winter natural gas prices.

This really shows that estimating future production from any natural gas or oil play is filled with many unknowns–despite what the shale promoters say.  The complexity of projects, whether offshore, shale or conventional, makes future production forecasts increasingly unreliable.  

You need production history from a basin to have any accuracy in estimating future production.   Then everyone’s guesstimates become more meaningful.

Few new discoveries, declining production and high costs combined with increasing demand inelasticity due to the shut down of  many of America’s coal and nuclear will likely lead to extreme price volatility in New England in the short term and potentially much higher prices in medium and long-term.

Why Encana’s Deep Panuke Problems Matters for New England

By
Keith Schaefer
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0

Why EnCana’s Deep Panuke Problems Matter for New England

By: Bill Powers

Encana Corporation (ECA-NYSE/TSX) got lucky with high gas prices for its Deep Panuke project offshore Nova Scotia—but the failure of that play does not bode well for New England natural gas prices.

Along with Exxon’s Sable Island Energy Project (SOEP), also located offshore Nova Scotia, Deep Panuke was once expected to provide New England with ample natural gas supplies for years.

This bounty of gas would allow for the accelerated closure of the regions coal and nuclear plants and encourage the conversion of homes and business away from fuel while keeping electricity prices at acceptable levels.

Sounds great to me! However, things have not worked out according to plan.

Despite high expectations after the initial discovery well drilled in 1999, Deep Panuke has had a troubled life. The project came online years late, over budget and after less than two years of operation, appears headed for a premature death as operational problems plague Deep Panuke.

To be clear, offshore projects running into delays and cost overruns is nothing new.  In fact, it is the norm rather than the exception.

However, Deep Panuke’s problems combined with New England’s increased reliance on natural gas has created a toxic mix for consumers that will ensure the region will continues to have the highest prices in the US for natural gas.

So what? Won’t gas from the Marcellus flood the New England market once pipelines are built and make Deep Panuke’s problems a distant memory over the next couple of years? In Part II, I will explain how it is extremely unlikely New England will receive enough gas on a daily basis to drive prices down towards levels that much of the nation has enjoyed the past few years.

Let’s look at the economics: According to a recent Reuters article, natural gas prices for next day delivery at the Algonquin hub, which connects the Maritimes and Northeast Pipeline from Nova Scotia to the New England distribution system, traded at an average of $22.50 per million British thermal units (MMBTU) for the entire month of February 2014. (Source:http://www.reuters.com/article/2015/03/01/energy-natgas-newengland-idUSL1N0W125220150301 )

These prices were of course due to the Polar Vortex.  To translate, $22.50 per MMBTU gas is the equivalent of $135 per barrel oil and was far above the national average city-gate price of $6.44 per MMBTU.  (Source: http://www.eia.gov/dnav/ng/hist/n3050us3m.htm ).  While many believed that Polar Vortex caused a once in a century spike in natural gas prices in New England, it didn’t.   In fact, prices skyrocketed deep into the double digits only one year later.

During the above average cold and snow of February 2015, Algonquin prices averaged $17.73 per MMBTU (Source: ibid) versus a city gate national average of only $4.55 per MMBTU (Source: ibid).  Imagine that, in a world that was supposedly awash in cheap shale gas, major price spikes have occurred two years in a row.  It wasn’t just the weather!

While not good news for New England gas consumers, this was actually very good news for Encana.  The #5 natural gas producer in the USA has been able to recoup a majority of its investment in the project since it generated $395 million in cash flow during the Polar Vortex Q1 2014.  ECA was very lucky in that the start-up of Deep Panuke coincided with record high gas prices in New England.

But operational difficulties and shortened reserve life of Deep Panuke mean this cash cow has now run dry—and that’s not good news for ECA shareholders or New England consumers.

Shortly after discovery in 1999 by EnCana’s predecessor company, PanCanadian Petroleum, there were high hopes in the energy industry that Deep Panuke would marshal in a new era of exploration success in offshore Eastern Canada.

Large international companies such as ExxonMobil, operator of the nearby SOEP which produced its first gas in January 2000, EOG Resources, Kerr-McGee and El Paso and others hoped that advances in 3D seismic technology would bring forth additional new discoveries.

Even the Geological Survey of Canada estimated that there was at least 18 trillion cubic feet of natural gas to be found offshore Nova Scotia. (Source: http://www.aims.ca/en/home/library/details.aspx/428 )

However, five years and more than a dozen $75 million dry holes later, very little was found and companies began exiting the area in droves.  Despite the exploration misses and regulation hurdles, in early 2006 EnCana put forward a project development plant that estimated that at a cost of CAD$700 million, Deep Panuke would be producing up to 300 mmcf/d of gas through a 175 kilometer offshore export pipeline.  As you can see from the below graphic, both SOEP and Deep Panuke connected to the mainland at Goldboro, Nova Scotia:
deep-panuke

Source: http://www.cnsopb.ns.ca/offshore-activity/offshore-projects/deep-panuke
According to EnCana’s original development plan for Deep Panuke the field would begin producing up to 300 mmcf/d in 2010 with a mean expected lifetime recovery of 630 bcf and an expected average life of 13 years.

However, first gas was not achieved at Deep Panuke until August 2013 at a cost of approximately $1 billion, nearly 50% over budget and three years behind schedule.

The below chart shows how monthly production from Deep Panuke has fluctuated greatly since start-up:

deeppanukemonthly

 

Source: http://www.cnsopb.ns.ca/sites/default/files/pdfs/dp_monthly_prodution_plot.pdf

Though Deep Panuke has been producing for less than 2 years, the end of its life is already in sight.  The field produced an average of only 170 mmcf/d between November 2014 and March 2015, 50 mmcf/d or 23% less than the prior year period.  It should be noted that this fall-off in production came despite gas prices averaging well into the double-digits during this period.
(Source: http://thechronicleherald.ca/business/1290392-region%E2%80%99s-gas-scarce-nova-scotia-power-says )

After cutting the reserves in half in February 2015 from 400 bcf to less than 200 bcf (only 80 bcf is remaining to produce after 69 bcf was produced as of year-end 2014) EnCana also announced that Deep Panuke will only produce during the winter months—when gas prices are at their highest point during the year due to excessive water in the reservoir. (Source: Ibid)

Similar problems are emerging at Exxon’s SOEP where production has been falling for years and averaged 175 mmcf/d during January 2015.   SOEP was expected to produce for another 13 years, however a recent regulatory filing by Nova Scotia Power suggests that Exxon will be shutting down the field as early as October 2016.
(Source: http://thechronicleherald.ca/business/1231141-taylor-nsp-may-be-right-about-sable-gas-cutoff )

With less than 80 bcf remaining at Deep Panuke should EnCana be able to successfully manage the unexpectedly high volumes of water that have encroached into the reservoir and Sable Island likely to shut down in 18 months, where is New England going to get its gas?

I will explore that in Part II of this story early next week.

What’s So Bullish About Canadian NatGas?

By
Keith Schaefer
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0

Why are recent natural gas deals in the Western Canadian Sedimentary Basin (WCSB) getting done at very expensive metrics, when the consensus for Canadian gas prices in the near to medium term is lower—potentially a lot lower?

The obvious answer is LNG—Liquid Natural Gas exports; even though the first exports are realistically a minimum five years away.

That theory got a boost on June 11 as Petronas gave a conditional positive Final Investment Decision (FID) to its Lelu Island LNG project.

The first gas deal—the May 27 sale by Leucrotta Exploration (LXE-TSX; LCRTF-PINK) of 1,300 boe/d (87% gas) for $80 million in the Alberta Montney play.  The buyer was unnamed but almost certainly was Tourmaline (TOU-TSX; TRMLF-PINK).

They own all the land surrounding the acreage that Leucrotta sold, and it’s in the vicinity of their Lower Montney Turbidite play (Turbidite=buried river delta) which is getting a lot of attention and capital.

Canadian brokerage firm National Bank reports that transaction metrics implied by deal are $61,500 per flowing barrel of oil equivalent (natural gas is converted to oil at 6:1, meaning 1 million cubic feet a day is 166.667 barrels of oil equivalent per day, or /boed) and 17x price-to-cash-flow (P/CF) at strip pricing.

Compare that to the 12-month average gas-weighted transactions at $32,270/boed and 6.2x P/CF, or an estimated $6,200/ac vs. historical Montney transactions at $4,400/ac (if production is assumed at $25,000/boed to make them all equal);

You can see those metrics are
1.   50% higher on an acreage basis
2.   almost double recent sales on a per flowing boe basis,
3.   and triple the value on price to cash flow basis

Then on June 9, privateco Black Swan Energy Ltd. acquired another private company Carmel Bay Exploration Ltd. for $6,800 an acre, in a $200 million deal including debt.

In a depressed market looking for deals amongst potentially distressed sellers, neither of these transactions seem like a bargain.  So what’s going on here?  Why are some producers opening up their wallets (and sacred balance sheets) to pay top dollar for these assets?

Natural gas plays are being sold for much less outside the Montney—and farther away from west coast LNG terminals.  Tamarack Valley Energy Ltd. recently bought more acreage in their core Wilson Creek region in south central Alberta.  They bought 1,450 BOE/d (55% natural gas) and 6.44 million of 2P reserves for $54 million.  And there was almost $60 million of infrastructure (e.g. pipelines; oil storage tanks called batteries and processing facilities) on the play!

Even valuing infrastructure at zero, these metrics come out to a seemingly miserly $37,500 per flowing barrel and $8.40/bbl of reserves–numbers that are more representative of a gas weighted ratio.  Infrastructure definitely wasn’t part of the Leucrotta deal.

So right now Montney gas assets are selling at a premium, almost like it’s oil. (Crescent Point (CPG-NYSE/TSX) just bought the oil weighted Legacy Oil and Gas (LEG-TSX; LEGPF-PINK) for $70,000 a flowing barrel).  That begs the question, why is someone paying a premium for natural gas today!?  Gas inventories in storage in both Western Canada and the United States are still (very) high for this time of year.

Alberta is already at 70% of capacity with over four months to go in the injection season (which usually starts 2nd week of November)!  Total storage in Canada is 143 Bcf higher than 2014 (as of June 8).  Gas production is up in western Canada for the first time in five years—about 800 mmcf/d, or 0.8 bcf/d.  Exports to the US are only up 0.46 bcf/d (mostly to the drought stricken California market).

And because of forest fires, a lot of heavy oil production in western Canada was shut in May and early June, reducing natgas demand by 0.9 bcf/d for a time.  That’s a bearish 1.7 bcf/d swing for awhile.

And later this summer, new natural gas pipelines from the Marcellus into the US Midwest by August and into Ontario in 2016 will further isolate WCSB gas—forcing it to reduce pricing to sell any product at all.

Canadian brokerage firm Scotia McLeod came out on June 16 saying prices needed to drop a minimum 10% quickly to keep competitive.

It’s not a pretty picture—for several years.

The story south of the border is not much better with current storage levels of 2,344 BCF being 47% above last year and 2% above the 5 year average.  Current natural gas prices are reflecting this with AECO spot prices down almost 50% from last year at around $2.50 per GigaJoule.

This doesn’t paint a compelling picture for natural gas and certainly doesn’t explain why anyone would be paying top dollar for Canadian natural gas assets right now.

There are a couple potential reasons for this.  Technology has improved a lot in the last year.  A fracking system called “NCS multi-stage” is now being used in the Montney, where producers can frack one stage at a time and see how much gas or oil is coming out.  It also allows producers to tell if frack stages are “communicating” or stealing hydrocarbons from the last frack stage.  This means producers can tell exactly how many fracks they need to do per well; what is the optimal distance between fracks to maximize the amount of oil or gas the well can produce.

The NCS system has been around for awhile, but not in the deeper Montney.  Producers I speak with say it’s generating a 30% increase in production for the same all-in price of a well.

The other reason is – LNG exports.  In fact, western Canadian gas really is a binary trade on LNG exports (at least it is until the monster Marcellus formation in Pennsylvania peaks in its natgas production).

Think what you want about the chances of any Canadian natural gas shipping off either coast before 2020, there are several producers out there positioning themselves to be ready.  And those producers are betting with real money.

These transactions show some producers aren’t worried about diversifying their asset base or getting the best deal.  They are strategically positioning themselves for the day Canadian natural gas can compete on a world pricing basis and escape the depressed pricing of the domestic market.

As an investor, you have to factor this in to your decision.  If you think it’s a pipe dream (pun intended) that investors will see LNG exports off the BC coast in our lifetime, then you’ll avoid stocks who are paying a premium for Montney assets.

Now, even this long term theory for land value is a bit suspect.  The two leading LNG candidates—Petronas and Shell—are already the #5 and #6 gas producer in the WCSB—and they have big land positions.

A recent study by boutique energy firm Peters & Co. shows that Progress Energy (owned by Petronas) has 2109 square miles, or sections of land in Northeast BC.  Shell has 886 square miles between NE BC and Alberta’s Deep Basin area.

Exxon and Altagas are next in line.  Exxon has 840 square miles in the Alberta Montney.  Alberta utility Altagas has a deal with Painted Pony (PPY-TSX; PDPYF-PINK) for its gas supply, and PPY says they have enough to support a 2 bcf/d LNG facility for 20 years.

The LNG player who was expected to be a big buyer of supply was BG Group—but they were recently bought out by Shell.  That LNG plan is likely a no-go now.

So buying expensive Montney land thinking you can sell it to a major LNG player for as much or more in the coming 2-4 years…for investors, that’s a speculative trade.

Through all this, multiples in the sector have increased for the leading producers and even many of the mid-tiers in the Montney as condensate and natgas prices have declined. (Think 15x cash flow vs. 10x before.) That’s likely another reason some buyers—and Tourmaline is a leader—are paying what they are.

Not to say there isn’t value in the Montney–but it’s going to be tough to find if producers keep paying these types of prices.

Keith Schaefer

Editor’s Note: I just made the largest purchase ever – $400,000 worth of my personal money – of a company with an 8.5% yield, almost no debt, and two leading American companies as its partners. I think the dividend from this stock will pay for my retirement. Check out the story here.

The Texas Natgas Massacre

By
Keith Schaefer
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0

By Bill Powers

Natural gas production in Texas in Q1 2015 declined 1.5 billion cubic feet per day (bcf/d), results from the Texas Railroad Commission (RRC) show.   That’s a 5.5% decline on the 22 bcf/d Texas produces—a full one third of all natural gas production in the USA.

Conservatively, I expect a 15% decline in the Lone Star state for all of 2015. That would result in a loss of more than 3 bcf/d.

In fact, that’s very conservative as the collapse in Texas rig count from 891 a year ago to only 373 for the week ending 5/15/2015—a 58% drop—is having a profound impact on gas production in the state.

The combination of thousands of wells drilled in the past few years that are still in the high-decline portion of their lifecycle and such a large reduction in drilling activity indicates that Texas is on track for an epic decline in gas production in 2015.

To be sure, the reduced output is partly to blame on slumping activity levels.  Investors should remember that the 1.5 bcf/d decline in Q1 2015 occurred with an average of 647 land rigs running in the state.  As of May 15, 2015 there were only 372 rigs working in the state.  (Source: Baker Hughes)

But there’s more.  I’ll explain how wells are now getting lower IP rates than before, and data that clearly shows new wells are stealing production from older wells (The industry says that when that happens, wells are communicating.)

Now, considering there is usually a six-month lag between falling rig counts and declining production, the drop in Texas in the first three months of 2015 is remarkable.  More importantly, the quick drop in Q1 indicates the second half of year is likely to see a more pronounced fall off in production barring a quick rebound in activity.

Below is a table tallying up the declines by major Texas plays in Q1 along with conventional production as well as my projected decline for the entire year:

Play Name Decline in Q1 2015 Projected 2015 Decline
Barnett .4 bcf/d 1 bcf/d
Eagle Ford .33 bcf/d .75 bcf/d
Permian .2 bcf/d .4 bcf/d
Granite Wash .25 bcf/d .5 bcf/d
Haynesville 0 0
Conventional .3 bcf/d .6 bcf/d
Total 1.5 bcf/d 3.25 bcf/d

Now, let’s look at what the raw data is showing for each of the major gas producing basins in Texas, and what recent developments in Texas tell us about production for the rest of the US.

The Barnett Shale

The Barnett is the oldest modern shale play in the US with over 20,000 wells drilled into it over the past 15 years and has more than 16 Trillion Cubic Feet (TCF) of historical production.  Many analysts and operators have long professed that Barnett wells will produce for 40 years and have terminal decline rates in the 5 to 7 % range.

Devon Energy told me a few years ago that their engineers have estimated that the company’s wells in the play have a 6 % terminal decline rate.  However, history is indicating a much steeper rate.  Given that Devon is still the largest operator in the Barnett, the company’s estimate of terminal decline appears to be grossly understated considering the large fall in production in first 3 months of 2015.

The below graphic from the RRC shows a 0.4 bcf or 9 % drop off in natural gas production YoY in the Barnett in the first 3 months of 2015:

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One would expect that the average Barnett well decline rate would now be in the high single digits given that the average age of each well is more than 5 years old. However, this has not been the case.   The Barnett shale is on pace to decline an incredible 20 % in 2015 despite the drilling of new wells.  Put differently, the Barnett is on track to see production fall from an average of 4.9 bcf/d in 2014 to only 3.9 bcf/d this year.

The reason for the drop-off in Barnett production (and other shale gas plays) is quite simple; despite improvements in technology, the average well is becoming less productive (i.e. lower initial production (IP) rates and has a lower estimated ultimate recoveries (EURs)).

There are two main reasons for lower well productivity:  1) declining rock quality 2) and interference with neighboring wells.  It has been well documented how the best wells come from small geographic areas commonly known as “sweet spots” and the further away from these areas the less productive wells become.

In the Barnett, the average new well in 2014 came online with an IP rate of less than 1 million cubic feet per day, down 20 % over the previous few years (Source: Drilling Deeper, David Hughes), and will recover less than 1 bcf in its lifetime.   My estimate of 1 bcf of lifetime production is due to the .8 bcf the average well has recovered in the first five years of life and a realistic life expectancy of between 7 to 8 years.    While many analysts predict the average Barnett well will produce for multiple decades, the facts say otherwise.  More than 4,000 (20 %) of Barnett wells are already dead after less than a decade of production indicating a realistic lifespan of less than 10 years.  In fact, very few wells with a production history of ten years are still producing.

So how drilled out is the sweet spot of the Barnett?  Answer: Very.  The top three Barnett counties by historical production, Denton, Johnson and Tarrant, (about 75% of the Barnett’s historical production) already have more than 6 wells per square mile (640 acres or 5,280 square feet).

With fracture stimulations usually deploying energy in the reservoir at least 500 feet to nearly 1,000 feet in every direction from the wellbore, many wells in these three counties are producing from the same acreage.  While communication between wellbores will not always become apparent immediately after a well is drilled, lower than expected lifetime EURs are proof positive that too many are drawing on too few resources.

So what does the path forward for the Barnett look like?  With only 5 rigs running in the Barnett for the week ending May 15th, down from 25 a year ago according to Baker Hughes, it is clear we are seeing a permanent wind down of activity in America’s oldest modern shale play.

Based on recent new well productivity numbers for the Barnett, approximately 1,200 wells would be needed to keep current production flat in 2015.   However, we are miles away from this level of activity. I estimated that the five rigs currently running in the play will drill between 50 and 100 new wells this year.

In fact, production in the Barnett is declining so much faster than expectations that producers are now having to pay what’s called “shortfall fees” to pipeline operators.

That means they pay for the space on the pipeline for their gas—even when the gas just isn’t there.

One of the Barnett’s biggest operators, Chesapeake Energy (CHK-NYSE), warned investors on page 58 of its Q1 10Q regarding its outlook on Barnett production, “We anticipate incurring significant shortfall fees in the 2015 fourth quarter based on current production estimates.”

While CHK’s finances are in great difficulty due to its large interest and preferred dividend obligations and falling revenue, its remaining locations in the Barnett must be extremely uneconomic for it to pay “significant shortfall fees” for pipeline capacity it has already contracted for.   Over the next three years I expect Barnett production to decline from approximately 4.5 bcf/d currently to 2.5 bcf/d given the advanced maturity of the play and the actions of its biggest operators.

The Eagle Ford Shale

After 5 years of halcyon growth, Eagle Ford natural gas production has rolled over and is now in rapid descent.  As you can see in the graphic below, taken from the RRC website, Eagle Ford gas production has fallen .33 bcf/d or 7% YoY in just the first three months of 2015:

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I estimate that the huge decline in drilling in the Eagle Ford (the rig count has fallen to 108 from 219 a year ago) combined with very large well decline rates will cause production to drop approximately 0.75 bcf/d in 2015.  Even though the Eagle Ford has 21 times the number of rigs running as the Barnett, it will see a similar natural gas production decline.

As drilling has moved to the oiliest part of the play (such as Karnes County) as operators high grade their drilling prospects, each new well drilled this year will produce less gas than a new well drilled last year.  Considering the annual field decline rate for the gas portion of the play (how much production would drop if no new wells were drilled) is 47 % (Source: http://www.postcarbon.org/wp-content/uploads/2014/10/Drilling-Deeper_PART-3-Shale-Gas.pdf) and the 3-year decline rate is 80 %, production from the Eagle Ford production is likely to continue to fall for several years barring an immediate and significant pick up in drilling activity.

The Permian Basin

Times have changed drastically in the Permian Basin over the past year.  The rig count has collapsed more than 60 % and shows no sign of rebounding without significantly higher prices.

While oil production in the Texas Permian has fallen only 1 % in the first three months of 2015—natural gas production has declined 5 %.  As you can see from the below table, gas production in the Texas Permian was down an average of .2 bcf/d in the first three months of 2015 compared to the annual average of 2014:

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Though gas production in the Texas Permian is down only .2 bcf/d in the first three months of the year, I estimate there will be a drop of .4 bcf/d for the entire year given that associated gas production typically has very steep decline rates.

The Granite Wash

While the Granite Wash play of North Texas and Oklahoma does not get as much attention as shale plays, it has been an important contributor to both US oil and gas supply in recent years.

The downturn in prices has cut drilling in the play from 62 rigs a year ago to only 16 today and as you would expect, production in the Texas portion of the play has rolled over.  As you can see from the below graphic, natural gas production is already down .25 bcf/d, or 26 %, in the first three months of 2015 and now at levels last seen in 2008.

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Texas Granite Wash production appears on track for a .5 bcf/d fall in 2015 given the lack of drilling.

Texas Conventional Production

Texas still produces between 6 and 8 bcf/d of conventional natural gas depending on how you classify a portion of the gas production from the Permian Basin.

Given that very little drilling has taken place in the past six months on conventional prospects in Texas or anywhere else in the country, I estimate that conventional production in the state has fallen .3 bcf in the first quarter of 2015 and is on track to fall .6 bcf/d for the year.  For example, one of the largest areas of conventional production in the state is in south Texas where operators have been producing from the Frio and Vicksburg formations for decades.  This area has very high decline rates and has seen limited drilling in recent years due to low prices and its advanced maturity.

What the Drop in Texas Production Means for Rest of US

With Texas producing about a third of all natural gas produced in the US on an annual basis from a variety of different formations, it is an excellent proxy for the US industry as a whole.

For example, though other states such as New Mexico and Oklahoma did not experience the drilling boom to the same degree as Texas, and each state has seen its rig count fall substantially over the past 12 months.

New Mexico’s rig count has gone from 89 to 44 in a year—a 50 % drop—while Oklahoma’s has fallen from 195 a year ago to 103 recently—a 47 % drop.

Overall, investors can reasonably expect a material drop in natural gas production in every gas producing play in America with the exception of the Marcellus and Utica where production looks to have flattened out in Q1 2015.

In other words, with US natural gas production in decline and activity levels at multi-year lows at the same time demand continues to ramp up, prices should move materially higher during the balance of the year.

EDITORS NOTE–Higher natural gas prices will first benefit the lowest cost producers.  My favourite junior producer already has a huge play where the wells payout in just 12 months at current prices.  That’s unheard of! It gives investors a free call on natural gas prices rising–and one of my Top Picks for the second half of 2015.  Click here to access the name, ticker, and full report on this low cost producer.

-Keith

The Stock to Own if US Oil Production Stays Stronger for Longer

By
Keith Schaefer
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The Opaque World of Crude Oil

The latest EIA stats painted a seemingly bullish picture for North American crude oil right now.  Crude prices have rebounded from the March re-test of the low, US production seems to finally be falling and Cushing storage levels are starting to draw down.  The story is all good for the North American producer…or is it?

The strong rally in WTI from Mar 17 to May 5 can be largely explained by hedge fund short covering.  In mid March, hedge fund short positions peaked with WTI-linked futures and options amounting to 209 million barrels of oil.  Since that time, hedge fund short positions have declined more than 55% to roughly 93 million barrels.

During this same period of time hedge funds only added 2% to long positions in oil or roughly 7 million barrels.  Not to say that fundamentals don’t play a part in price, but the hedge funds tend to accelerate and/or exacerbate the moves in price in both directions.

There isn’t a material amount of short positions being added to or covered now, nor is there much activity on the long side either, which is one reason WTI has stalled out in the $60 range for the last month.  The hedge funds seem to be moving to the sidelines until they can predict which direction crude will move from here.

Next up, let’s look at the domestic production drop reported in last week’s EIA data. Looking at this data on a weekly basis can be deceptive.  Part of the most recent weekly decline was due to curtailed Alaskan production due to full storage tanks at Valdez (estimated to be ~90,000 b/d) and some of the decline is a function of offshore Gulf Coast maintenance (peaking at roughly ~200,000 b/d).

That would mean Lower 48 production is still as high as ever.

The Gulf Coast maintenance will have a ramp up and ramp down period so it will be difficult to clearly assess its weekly impact, while the Alaska situation is expected to clear itself up for next week’s stats.  It’s plausible that over the next 1-2 weeks we could see US production rise back to peak 2015 levels, which has to be disappointing to oil bulls who were expecting the sharp production declines in light of the dramatic drop in North American rig counts.

Lastly, Cushing storage draws aren’t necessarily bullish right now as they aren’t even drawing down as quickly as last year. This means that on a year over year basis, the storage surplus is still increasing.  Given the fears the market had in March and April of US storage reaching capacity, any storage draw is viewed as bullish in absolute terms…but perhaps we aren’t out of the woods yet.

Of course all this is analysis is predicated on the information available to the EIA.  Along with the EIA and other data resources like OPEC and IEA the unfortunate reality is that all the information that is published today is imperfect at best and in many cases, is simply an educated guess.

National Oil Companies (NOCs) have no need or desire to report any of their activities.  It’s all but guaranteed we aren’t getting accurate information out of Libya, Iraq, Yemen, Iran, etc.  All of the data above would tend to be bearish.

It’s interesting to me that for all the specialized, big name firms who analyze one of the planet’s biggest industries–no one is completely accurate.  It’s not even absolutely necessary to ascertain who is the most correct.  You have to understand who the Market believes is the most accurate—because a shift in direction from the Market leader will likely be the signal as to which direction prices go next.

In the meantime, because of the opacity of information in the crude oil market, the individual investor has to be vigilant about what stocks you own.  The stronger the underlying value of the company, the less it will be hit by a downward move in prices and the more it should benefit from a price upswing.  For energy investors, it means mostly owning the leaders among the producers and other sub-sectors.

But what if you own a stock that benefits from a lower oil price?

Now, the one FACT I see in the oil market is that the US rig count is down some 60%, while oil production is barely off 1%.

At the beginning of 2015, I suggested US oil production would stay stronger for longer than the Market expected.   So far that’s happening—despite a much stronger drop in rig count than anyone thought.

If this trend continues, there’s one stock—A Market Leader—you want to own—CLICK HERE to get my full report.

 

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