Strange CHK news release- Horrible price differentials in Northern Marcellus region- liquidating CHK position

I haven't done any detailed post about the Marcellus region, and I do plan on doing that at some  point.  Yesterday RRC reported pretty much inline earnings (although concensus had decreased over the past few months, as ussual).  Their 15x EBITDA valuation is still far to rich for me, although I think they are an outstanding company with a premier acreage position in the SW Marcellus.

Yesterday CHK put out a news release with several unrelated pieces of information.
1) they are doing an acreage exchange with a small private company involving swapping Powder River Basin oil acreage.

2) They are buying back preffered shares in their Utica subsidiary worth $1.26 B - anything that simplifies their incredibly complex balance sheet is a step in the right direction.

3) They prereported that their realizations for the trailing quarter in the Northern Marcellus, where 29% of their gas is produced, is expected to average $2.47 per MCF below NYMEX.  

WHAT???  How is this even possible.  NYMEX is at $3.75 right now.  We must be getting into severe take-away capacity constraint situation right now.  Its hard to believe that they wouldn't just start shutting in wells with these prices.  This isn't a momentary differential, it is for an entire quarter, and we still have another quarter plus before the draw season starts.  Any temptation to buy Cabot or other Northern Marcellus producers is totally gone for me.  It doesn't matter how cheaply you can take it out of the ground if there's no where to put it.  Company wide differentials for the quarter are likely to be over $1 below NYMEX according to the release.

I'm not usually inclined to react to short term news like this, but the fact that the market hasn't reacted more to this news makes me nervous for a big fall when they report.

Production Sharing Contracts

After the prior post on land leasing in the USA, I thought I'd also do another post on a typical contract structure used in other countries where the government owns the mineral resources but foreign oil companies produce the oil.  Under the structure of a Production Sharing Contract (hereafter PSC), first used in the 1960s, the foreign oil company recieves a share of future production as remuneration for exploration and development of the oil resources in a certain area.  There are several other structures that have also been used, such as the concession, the joint venture, and the service contract.  But these are less relevant for Exploration and Production companies, and I'm not going to go into details about them here.

In a PSC, a foreign oil company is awarded a concession for a particular geographic area, and they are responsible for the costs of drilling exploration wells.  If and when production of oil and gas  commences, these costs are generally paid for out of the first oil that is produced.  This is called “cost recovery”.  Then profits are split between the government and the contractor according to some formula.  In certain countries, like Indonesia, the formula is incredibly complex.  In Egypt, where Apache operates it is quite simple.

In the case of Egypt, first the oil is divided 60-40, with 40% of the oil going into a cost recovery pool.  Capital costs from the drilling are then paid back to the company out of this cost recovery pool.  In some countries they are paid back as fast as money flows into the cost recovery pool, but in the case of Egypt, they are paid out at a pre-determined 20-25% per year rate of depreciation.  So if Apache spends $100mm drilling, then they get $25mm/year for four years out of the cost recovery pool.  If there isn’t enough money in the pool, then they get an IOU from the pool to be paid out if and when money becomes available.  They also receive operating costs out of this pool.  Extra amounts left over in the recovery pool flow over to the profit pool.  In the case of Egypt, the profit oil is then split 80-20 with the government receiving 80%.  The 20% is free and clear of any Egyptian taxes though.  Each concession area is “ring fenced” so the contractor can’t recover money from another concession, if exploration is unsuccessful.

Although these terms may not seem particularly generous, it is actually a great deal for Apache, because this is relatively easy oil to get, and capex costs are quite moderate since it is all on-shore.  Offshore PSCs can be a bit more fraught with risk because of the huge amounts of capital involved.

It is also worth noting that the risk profile of a PSC like this is totally different than drilling for expensive oil on-shore in the USA.  For instance, take a Bakken well that costs $8mm to drill.  If the price of oil was cut in half tomorrow, it would be very difficult indeed to recover the costs spent drilling the well.  Unless the company had sold their oil forward in the futures market, they would most likely have lost money drilling this well.  But in the case of Egypt, Apache receives money out of two sources, from cost recovery oil and from profit oil.  The cost recovery portion of their revenues might not be effected at all by the decline in oil prices, since at present only about half of the available money for cost recovery is actually used, the rest is sent over into the profit pool (see image above).  The profit-oil payments might go down by 2/3s, but overall Apache is at much less risk of actually losing money than someone drilling for expensive oil onshore in the USA.  They might make less profit than they had hoped, but they would still not lose money.  Because of this type of contract structure the large international oil majors can still make a profit when the price of oil goes way down. 

Although there is less risk of losing money due to resource price volatility in a production sharing contract, there are sometimes big political risks.  Contract terms have been cancelled or altered to the disadvantage of the company at times in the past.  After the contractor spends the upfront money to get things going, there may be a big temptation for the government to take a bigger portion of the resulting revenues than they had promised the company to lure them there.  

For an investor there is another difference between on-shore US exploration for expensive oil vs doing large foreign oil projects under production sharing contracts.  The foreign PSCs and particularly offshore contracts favor companies with lower capital costs while on-shore US projects favor companies with more efficient (lower cost) operations.  Because of the cost recovery provisions in international contracts, there is less incentive for the contractor to skimp on spending.  They only care about getting the project done as fast as possible for the oil to start flowing.  All their high costs will be paid out of the cost recovery pool, and so will really be borne by the government.  For on-shore US, every dollar of cost comes out of the company’s profits, since tax revenues and landowner royalties are paid out of gross production.

An explanation of the Egypt structure is available from Apache here:

http://files.shareholder.com/downloads/APA/0x0x728759/af4015b8-478d-4506-a57c-7558d74b1a0a/Apache_Understanding_Egypt_20140226.pdf

Here is a nice (very long) history of the PSC, which I haven't read all of:

http://www.oxfordenergy.org/wpcms/wp-content/uploads/2010/11/WPM25-ProductionSharingAgreementsAnEconomicAnalysis-KBindemann-1999.pdf

Digression into Unitization and Pooling Laws

Prior to a more detailed discussion of Whiting's position in the Bakken, I thought I'd do a post on the concept of unitization and also discuss land leasing practices in the US.

Private Oil Leases:

Unlike almost any other country, in the USA the landowner also owns the mineral rights below his land, and can generally authorize an oil company to drill on his land.  There may be exceptions to this where local laws might prohibit drilling.  In offshore regions like the Gulf of Mexico, the state owns land up to a certain distance from shore, and the federal government owns the land beyond that up until international waters are reached.

An oil and gas lease is generally a fairly simple document, and it is usually shorter than the lease you might sign for an apartment.   The general structure is that the leasing company pays the landowner a "bonus" which is an upfront payment for the lease.  Often the bonus is discussed in terms of dollars per acre.  $1,000 or $2,000 per acre might be typical, although it can vary considerably.  Then the landowner will also receive a royalty, which is a percentage of the gross value of oil and gas produced by the well.  In some periods an eighth was fairly standard (12.5%), though in many of the current plays, 15-20% is more common, and royalty rates can even be higher than that.  25% would be considered a very high royalty rate.

Most states also have a production tax on gross revenue.  In the case of North Dakota, a C-Corp (such as an oil company) would pay 4.53% of gross revenue as a production tax to the state.  The individual landowner pays a 3.22% tax on revenues he receives from his royalty..  Oil and gas production taxes now make up over 50% of North Dakota's state government revenues.  For the individual landowner these royalties (after paying the production tax) are also taxed as personal income by the federal government and state government just like earned income would be.  In financial reports, the oil companies will be reporting in net numbers, after subtracting the royalty amount, unless they specifically note that the number they are talking about is gross production.  Canadian companies producing in Canada, where royalties are paid to the government, report production in gross terms before royalty, making them a bit tricky to compare to US companies using some valuation metrics.

Now as long as a lease is producing oil, the oil company will retain its ownership of the lease.  This period might extend for many decades down the road.  But if the lease is not drilled within a pre-determined expiration date, or the lease is drilled but it is not found to produce a commercial amount of oil, then the lease agreement will expire.  In some cases the expiration might be in two years.  In others it might be in as much as 5 years.  Many recent leases also offer a renewal clause, allowing the oil company to have an option to renew upon expiration for a second term, but they must pay another bonus to the land owner.

In some states, the oil company only holds the mineral rights that are closer to the surface than the depth they have drilled.  In other words, if they drill a well to 4,000 feet and are producing oil, then they only retain the rights to all the oil at that depth or closer to the surface after the original expiration of their lease.

Unitization:

Originally oil reservoirs were governed by the “rule of capture”, where anyone could extract oil as long as they had the permission of the landowner at the location where they were drilling.  This led to extremely wasteful practices where hundreds of oil derricks might be set up around the site of a discovery, with wild drilling on every patch of land big enough to fit a derrick.  Inevitably this would damage the reservoir, since all the wells were rushed.  The fields would typically run dry very fast, since water ingression and inefficient production would damage the reservoirs and leave most of the oil trapped underground.   

Huntington Beach oil field in California during the "rule of capture" period.

The concept of unitization was born out of a need to stop the chaotic rush to be the first to drill into the reservoir.   In unitization, every landowner in the designated area shares equally in the production according to their share of the land.   The unit size is established by a state commission that sets out to determine the most geologically efficient size to drill.  Gas wells in Oklahoma were typically 1 mile by 1 mile sections (640 acres).  

My sense is that the drilling unit today has been more standardized and doesn't really relate to the area of land that can support a single well.  In many of these shale gas or tight oil regions they end up drilling a number of wells on a unit.  But the concept of unitization is still important, because it is an equitable method of sharing out the revenues among the landowners, and ensures more efficient development.  In North Dakota, these units tend to be one mile by two miles, because a Bakken well tends to extend underground for a distance of two miles in the horizontal direction.

Unitization also allows the companies to have an amount of space sufficient to drill a series of horizontal wells from a single site, known as a well pad.  Ussually there is an optimal direction for drilling into shale or tight oil to maximize the effect of the hydraulic fracturing.  A similar analogy would be how it is much easier to chop wood with the grain than against it.

Above you can see the drilling units in the Colorado Redtail oil play.  The vertical lines within each square represent wells.  When one of these wells starts to produce, all the landowners in the unit share the royalty income according to their ownership percentage of the land in the unit.  When the second well starts producing they all will share equally in that as well.

Besides the operator and the landowner there may well be other royalty owners as well.  In some cases an oil company might sell an ownership stake in a well to a financial partner, who would then be obligated to put up money for the initial capital expenses in proportion to their stake (unlike the landowner), but would also receive royalties in proportion to their stake.  The company Northern Oil and Gas, exclusively does investments like this as their entire business, and they do not directly operate any drilling rigs.  Oil companies might also sell a "royalty interest" in a property that is already producing, in exchange for an up-front cash payment from a financial partner.  Investors  in the oil company may rightly look upon complex transactions like this with some skepticism, since creative financing is often a sign of trouble.  But theoretically transactions like this can make sense if an oil company can achieve a much higher return on capital than the investor can when the oil company uses that money to drill another well.

Weekly Price Check

Nymex gas has continued its decline since mid June, falling another 4.4% in the past week.  The Marcellus was once again the weakest region.

Noble Energy (not to be confused with Noble Corporation, the drillship lessor) reported earnings Thursday and the stock seems to have reacted particularly badly.  Noble has one of the most premium valuations among the diversified large-cap E&Ps.  I have not listened to the call, and am not familiar enough with Noble to understand why the stock reacted poorly when they beat consensus.  Their main areas of interest are in the Denver Joules Basin in Colorado, the WV/PA Marcellus, the US Gulf of Mexico, and the Eastern Mediterranean.  Colorado has recently been the subject of a political battle between pro and anti fracking activists, and their Eastern Mediterranean assets are in Israeli waters, and so could be vulnerable to the ongoing turmoil over there.

Cabot Earnings call

$330mm cash from operations vs. $276mm in capex and growth of cash flow in the neighborhood of 19% YOY for the quarter.  Production growth of 34% yoy for the quarter, with a significant portion of that growth in oil production from the Eagleford.  They are talking about share buybacks, which is incredible for a company growing at that rate.  Its incredible that they can growth so fast comfortably inside of cash flow.  I love everything about this company except the valuation of 12x trailing EBITDA.  

Valuation Check In

I wanted to check in on the valuations of these companies to see if there are any readjustments I need to do.  I'm still holding about 57% of the E&P portfolio in WLL, 24% in CHK, and 18% in APA.  There was no buying and selling over the period.

Overall I was able to outperform the market over the three month period from when we last checked in.  The majority of the out-performance is attributable to Whiting Petroleum, the largest position.  The Bakken in general was by far the best performing group, driven considerably by the WLL/KOG merger announcement.  Gas levered companies did badly, including all of the Marcellus companies and the two most gas-weighted diversified E&Ps, SWN and CHK.  CHK was my real loser over the period.  Note that the stock price for CHK is adjusted to include the current market value of the Seventy Seven Energy shares that were distributed to CHK shareholders in a spin out.

I also updated my valuation spreadsheet by checking into the net debt, sharecount and 12 month trailing EBITDA for each of the companies on Yahoo finance.

Despite the sell-off the Marcellus names remain very expensive.  Among the Marcellus names, RRC and COG are really the premier companies in my opinion, but I’m still content to sit on the sidelines for now even after they lost 15% over the last quarter.  Its still a bit of a mystery to me how these companies should be valued.  They have the lowest cost of production for any sort of energy in North America, but they are also constrained from exporting it, and there is so much damn gas that its hard to see prices rising much.

The Permian companies managed to outperform the market and the sector in general.  And the valuations just seem totally crazy to me.  Pioneer is a $34b enterprise value with trailing EBITDA of less than $2b.  This is just far to rich.  EOG is a much better company with better growth, better drilling prospects, and a history of terrific execution, and trades at 8.5x trailing EBITDA.  And that is after going up 20% in the last quarter.   I just don’t see how these Permian Basin companies can command the valuations that they’re trading at.

To me the real opportunities are in the diversified companies.  It does not make sense that Apache, which has operations in the Permian basin that rival both CXO and PXD in size should trade at ¼ their valuation.  It does not make sense that MRO (Marathon) should trade at such a small fraction of the Bakken producers either.   Marathon puts about 60% of their capital into the Bakken + Eagleford + Anadarko basin so why do they trade now where near the valuation of pure play companies?

Within the Bakken, Whiting remains a good value in my opinion, and I have not sold any shares despite the run they’ve had.  Whiting, after the Kodiak acquisition, will be similar in size to Continental, but again there is a large valuation gap.  As of today, the valuation is about 70% higher for Continental on a trailing EV/EBITDA basis.  If Whiting starts to trade up into the 9x EBITDA range I may take some profits, but I’m comfortable with the valuation because I think that Whiting’s capital efficiency is likely to continue to show improvement.

New valuation spreadsheet notes shown below.  this is probably pretty boring, but I included my notes from this exercise.  I was comparing sharecount, net debt, and 12 month trailing EBITDA since last check in April.

Diversified:

EOG-  Sharecount climbed by a few hundred thousand since January, presumably due to executive options.  Net debt shrank from 4.5b to 4.24b.

APA- Sharecount was down to 385.7 from 395mm, or about 3%.  Net debt climbed a bit from 7.5b to 7.87b.

APC- Debt shrank from 10.5b to 8.5b (there must have been asset sales here).  Sharecount crept up a bit.

HES- debt went from 3.76b to 4.29b.  Sharecount decreased by 4mm to 318.1

OXY-Debt went from 2.9 to 4.750b Sharecount decreased by 10mm to 785.61mm

MRO- Debt decreased from 6.5b to 4.5b (overseas asset sales?).  Sharecount decreased by 20mm to 676.06.  A 3% decrease in sharecount over 6 months is pretty impressive, especially while also reducing debt.  They also pay a 2% dividend.  Maybe I should be looking more closely at MRO?

DVN-Debt increased MASSIVELY to 13.49b from only about 6b.  What did they buy??  Sharecount crept up a fraction, fairly stable.

CHK- Debt dropped DRAMATICALLY to 13.03 b, down about 4.6b from earlier.  A big chunk of this is probably from the CHK midstream spinout (Seventy Seven Energy).  Sharecount stable, declining slightly.

NBL-Debt up by 200mm to 3920mm.  Sharecount is perfectly unchanged.

SWN-  4b cash surplus to a 1.8b net debt?  What did they buy?

MUR- Net debt increased by 400mm to 2.430b.  ~2% decrease in sharecount.

PERMIAN

CXO- Minimal increase in net debt by 100mm to 3.77b.  Sharecount creeps up by .2%

PXD- Increase in net debt by 200mm to 2.45b (still quite low.)

LPI- Net debt up by $80m to 960mm

XEC- net debt increased by 200mm to 1.020b.

EGN- Net Debt stable, sharecount stable.

BAKKEN COMPANIES

WLL- Net debt increased by 700mm to 2.24b.  No change in sharecount at all.  Valuation is now looking a bit more full at almost 7x ebitda on a trailing basis.  Despite the big increase in price, this still looks like the best Bakken company to own from a valuation perspective.

CLR-Net debt up by about $1b to 5.020 b.  They are spending money like its 2011.

KOG-  Net debt stable at 2.24b.  At 3.5x net debt/ebitda, they were constrained from borrowing more.

OAS: net debt up by ~300mm to 2.20.  They are also running at 3x net debt/ebitda.

NOG: NET debt increases from 527mm to 900mm.  Sharecount is stable.  Their EBITDA must have increased too though.

Marcellus:

RRC:  net debt inched upward to 2.23b.  Sharecount is stable, but I know they authorized more share issues.  It must not have happened yet.

EQT: Net Debt creeping up to 1.70b from 1.4b.  Sharecount up by about 4m to 151mm.  That is a disconcertingly large amount of issuance for options incentives.

COG: Net debt stable at 1.19b.  Sharecount up by about 1mm to 417.

UPL: debt down from 3.8b to 2.4b.  They are now trading at just 7.4x trailing EBITDA?  Could they be a takeover target for someone like SWN?  The share price is about where it was when the original valuation was made, but it has been a bit of a wild ride indeed.

AR: Debt up by 700mm to 2620mm.  Sharecount stable.  Debt is going to have to go up a lot more too, because they have to drill like crazy to grow into their $18b valuation.  32x trailing EBITDA!  I’m skeptical about a company going so big like this.  I’d be interested to learn more about Antero, but my initial instinct is don’t touch these guys with a 10ft pole.  They are like Range, but less well established.  And in the Marcellus/Utica, you have to have scale to be able to get the take-away capacity.

Whiting Petroleum Part One

Similar to the earlier report on Apache, I wanted to dive into another company, which is currently my largest holding in my personal portfolio.  I was initially familiar with Whiting Petroleum from work I did as a financial analyst in early 2012.  I first bought shares in January of 2013 at $47.88 per share, and then I nearly doubled my position in October 2013, buying shares at $65.33 per share and I added to it again, in February 2014 at a price of $57.10 per share.  Since the current price is $87.98 as I write this, it has certainly been a good investment so far.  I don't want to be overly self congratulatory though, since indeed the entire market and the sector has performed terrifically well over the period.

The original reason that I bought shares was that it seemed to be a decently run company with a low valuation.  I became more excited about it in late 2013 because of several new developments.  First, they announced that they had found a field in the Niobrara formation in Colorado, which they called the Red Tail Field, where they had managed to lease up the core 90,000 acres.  They expected very high rate of returns on drilling there, and the size of the field is very material to Whiting.  They also announced the sale of several less economic properties in Texas.  Then in September they announced terrifically improved Bakken well results due to experimental improvements in their hydraulic fracturing techniques.  The claimed results were so dramatic an improvement, that even if they were wildly exaggerating the potential of this technique, it would still be hugely material for the company.

The most recent excitement is due to their announcement of their intended acquisition of another Bakken player, Kodiak.  The acquisition is a friendly transaction at basically no premium, and is all stock.  This acquisition should provide huge synergies, and combines Kodiak's premium acreage, with Whitings apparently better technical expertise.  Shareholders in both companies appear to be embracing the deal that will create a Bakken company with the highest overall production in the region ahead of Continental Resources.

Whiting History

I like to look at companies from a bit longer term perspective.  One nice thing about oil and gas companies is that it is often quite easy to look back at SEC filings and determine what things they have done well and what things they have done poorly.  A sense if history is also necessary to fully appreciate input from management during conference calls and press releases.  Some management tend to be highly promotional, and making grand projections that never come to fruition.  

Whiting went public in 2003.  From there through 2009 or so, they were a less focused company, opportunistically pursuing various opportunities.  They had prospects in the Permian, and they also bought several large mature oil fields to due EOR projects (enhanced oil recovery).  Conventional oil fields typically go through various phases of production.  Initially they may produce oil from their own internal pressure, and the oil just rushes out of the well bore.  Then as internal pressure is depleted, the oil is still pushed into the well bore by pressure from the geological formation, but now it must be raised to the surface with a pump.  Then later on, the internal pressure may need to be supplemented by artificial means which typically consists of injecting water or gas into the formation to raise the pressure of the oil reservoir and push the oil into the well bores of the producing wells.  Besides waterflooding, there is also a process called CO2 flooding, which is more expensive, but also more effective in some reservoirs.  Only a few companies have large CO2 flooding projects, because of the expense and technical complexity.  Whiting is one, along with Occidental Petroleum, and Denbury Resources to name a few.  Whiting had primary projects CO2 flooding projects that they focused on:

North Ward Estes Field:  This is 100% owned by Whiting, acquired in 2005 for about $450mm, at a only about $4.50 per BOE P1 reserves.  The field is only about 2,600-3,000 ft deep and was originally developed in the 1930s, with waterflooding commencing in 1955.  A CO2 enhanced recovery project was implemented in the core of the field in 1989, and Whiting re initiated more widespread CO2 injection in 2007.  Production was about 5,370 BOPD in 2006, but they are targeting 20,000 BOPD by 2016-2017, at which point management claims it should be valued at “well over” $2b ($100k per BOED not including gas).  This field required much more development and investment than did Postle.

Postle Field, Texas County Oklahoma: Acquired for $350mm in 2005 when it was producing at a rate of about 4.2mboed (although in a conference call in 2013 CEO says it costs them $240mm³ ).  The field was initially developed by Mobil in the early 1960s with EOOIP at 300mmboe, with about 118mmboe extracted (38.4%) as of December 2009².  It was unitized for waterflood in 1967.  In 1995 CO2 flooding was commenced.    From mid 2005 to 2009 they were able to nearly double production to 8mboed and were given an award from Oil and Gas Investor for “best field rejuvenation 2008”.  The field was sold in July 2013¹ to Breitburn Energy Partners LP.  for $860mm in all cash producing about 7.56mboed at the time.  Overall this was a great investment and great execution, although a large part of the benefit was due to the oil price doubling from 2005 to 2013.

This image from a 2009 Whiting report shows the results of their effort in the Postle field.  If you concentrate on the green line, you can see the production increase below the declining trend line, which occurs just after the commencement of CO2 flooding.  Production had been declining steadily since an initial peak in 1970.  Note that the chart is on a log scale, so the increase is actually quite dramatic.

Their other non-Bakken adventures have generally not been too profitable.  They bought gas producing properties in Utah at the top of the market in 2008 for $365mm.  This was a terrible purchase.  They also have spent significant amounts on their "Big Tex" prospect in the Permian, which has never really come to much either.

Chronology:

This part may be a bit tedious, and it was written for my own consumption last year, so there is a fair bit of short hand in it.

2003: IPO

2004: Company issued $240mm of stock issued at $29.90 (or at $15 based on current stock price after 2-1 split in jan 2011) to repay bank borrowings.  They also issued $150mm of 7.25% senior notes due 2012.

2005: Going Big.   They purchased 122mmboe of proved reserves.  $343mm was for the Postle properties, and $442mm for the north Ward Estes properties, along with 441,000 shares of stock (worth about $8.8 mm).   This represents a purchase price of $6.6/BOE of P1 reserves.  These were phenomenally well timed purchases, with oil at $50 per barrel, and about to go up dramatically.

They also acquired 116,000 acres in Montrail County North Dakoda (later the Parshall Field).  180 net wells were drilled.  Permian basin was about half of the 200mmboe proved reserves.  Rockies (which includes Bakken) was tied with the midcon region (Postle Field) for second place.   By far the bulk of the Permian reserves were in the North Ward Estes Field. 

To finance these purchases they issued $217mm of 7.25% Senior unsecured notes due 2013, and $250mm of Senior unsecured notes due 2014.  They also increased bank borrowing by $85mm, for a total of about $550mm increase in net debt.  They also issued $288mm worth of stock at $43.60 per share (or at $22 based on current stock price after 2-1 split in jan 2011) .

2006:  Reserve breakdown was little changed from 2005, though there was a 25mmboe increase in reserves.  The only reported significant purchases were some unproved acres in Utah and Michigan.  They drilled two exploratory wells in Montrail ND.  Total drilling activity  increased to 322 net wells.

2007:  Little in the way of acquisitions except for 13,470 acres of non-op interest in the Parshall Field in Montrail (operated by EOG?).

They sold their 50% non op interest in a few Texas gas fields for $40mm (pretax gain of $29.7mm).  This is not particularly significant, but it was a great move to divest this as the gas market approached a top, peaking out about a year later.  They drilled three more Bakken wells, and apparently liked what they found, because their 10k for 2007 says they are going to go to as many as 9 rigs in the next year and drill 30-40 Bakken wells.

They drilled only 138 net wells in 2007, but the Bakken wells were probably more expensive than their typical vertical wells.

2008:  Caught up in the boom times.  This year was major development capex that really set the stage for future growth and profitability.  Cashflow increased dramatically to 760mm, but this was largely due to increases in oil and gas prices.  Capex exploded to $1.33b for a massive outspend of cashflow.  This $550mm outspend of cashflow was financed by about $200mm sale of Whiting USA trust, and the rest from increased bank borrowing.

 In April they IPOed Whiting USA Trust I, raising $215mm.  The trust has a net profit interest that terminates when 9.11 mmboe have been produced.  (what properties?  How much gas).  Selling oil at $20/bbl of P1 reserves doesn’t seem great to me, but maybe much of this was gas?

In May of 2008 they acquired interest in various producing gas wells on 11,500 net acres in Uintah County Utah for $365mm.  They allocate $80mm to unproved properties, and $2.48 per mcfe of proved gas reserves.  This was a horrible purchase at the top of the market.

Their Bakken play was really getting going, producing 7.5mboed by year end.  They closed the year with 83,600 net acres in the Sanish field, and the 18,300 net acres in the Parshal field.  Most of their production was from their non-op interest in Parshall (6.7mboed.)  They also acquired 111,500 net acres in the “Lewis and Clark” prospect in the southern Bakken.  This would prove to be an astute acquisition later.  By year end, 8 of 9 of their active drill rigs (not including their veritable fleet of workover rigs mostly active in the EOR plays) were drilling in the Bakken.

They also mention Niobrara prospects for the first time in their 10k from this year.  They drilled a few wells in Southern Wyoming.

They increased production at Postle to 7.1 mboed net by year end from 5.8mboed.  North Ward Estes production increased from 5.1mmboed to 6.6mmboed.  They spent a huge $325mm of development capex on their EOR projects in these fields in 2008. 

2009:  The financial crisis, pulling back.  Drilling was curtailed, and they were down to 6 rigs by year end, all in the Bakken.  They dialed back their debt to cap from 40% at YE 2008 to 25% by YE 2009, mainly by issuing $334mm of preferred and $234mm of common stock, and paying down $460mm of bank debt.  There was a massive deterioration in CFO as gas and oil prices plummeted.   They were able end the year in good shape though, with a healthy balance sheet increasing oil prices, and $940mm of spare capacity on their revolver.  They guided to $830mm of capex in 2010 at YE 2009.  The stock price had tripled off its lows by YE.

They completed two acquisitions of overriding royalty interests around the North Ward Estes field for $65mm for $3.8mboe proved oil reserves.  These were completed near the end of the year and they must have been a distressed sale because the purchase price of $17.59 per BOE seems very low, unless the reserves will be exceptionally slow to pay out.  Superficially it seems like a very good price considering a royalty interest owner is not responsible for capex. 

They farmed out a portion of their Sanish field to a private company.  They sold a 50% non op WI and net revenue interest in about 30k acres, in return for a 65% drilling carry.   The company paid $108mm at closing for previously drilled wells, or currently drilling wells on the relevant acreage.  Overall this doesn’t seem like a great deal at all, and is either a sign of some distress, or that they have even more attractive units elsewhere.  Since it was 2009, it probably was a result of distress, but it may have been that they thought there were such big opportunities in the Bakken that they wanted the cash freed up.

They drilled three wells in the Lewis and Clark portion.

While the Permian still dominated 1P reserves, the Rocky Mountain area surpassed it in 2P reserves by 2009 YE.

2010: Back in gear and FCF positive.  They ramped capex right back up but their CFO more than doubled due to a 16% increase in production and a huge increase in oil and gas prices.  Capex was concentrated on the Bakken development.  After tripling off its lows of 2009 by the beginning of 2010, the price doubled again in 2010.

It was a pretty quiet year for acquisitions, although they were doubtlessly continuing to lease up land in the Bakken.  They acquired 16,000 acres in Weld County CO for $20mm, and 90,000 marginal Montana Backen acres for $26mm.  The Weld County CO acres would become the Red-Tail Prospect, which is now getting some serious hype as I write this in 2013.  Their total acres in the Red tail prospect was 66k at this time.

Their 18,000 net Parshal-field acres operated by EOG were actually seeing declines.  Most of these had been drilled in 2007-2008.  But the production on their 66,000 acres in the adjacent Sanish field nearly doubled to 23.5 mboed.  They grew their Lewis and Clark inventory to 235k acres.  They had drilled six horizontal Three Forks wells by YE 2010, which had averaged fairly respectable IP30s of 600 boed.

Postle maintained 8.9 mboed, and North Ward Estes was producing about 7.4mboed over the year. 

2011: Slow down and investor jitters.  2-1 stock split in January.  But investors began to realize that this wasn’t a story of boundless uninterrupted production growth.  As the Sanish and Parshall acreage was drilled out (though more recently EOG and Whiting both went back with much higher drilling density in other benches of the fields), the growth slowed.   Whiting outspent capex by a massive $600mm while only growing production by 6%, a seemingly terrible result.

The market as a whole got jittery due to the turmoil in Europe and the debt ceiling fiasco in Washington.  The macro and stock specific issues caused the stock to get cut in half at the lows of august.  It later bounced back somewhat, but years later it has still not eclipsed its previous high.

2011 was a quiet year from an acquisitions standpoint.  They bought 23,400 net acres in the Missouri Breaks prospect in Montana for $47mm.  They also bought 6k net acres in the pronghorn field of billings and Stark County ND for $40mm.  This was partly offset by sales of several noncore oil and gas properties in Texas for $65mm.

The Sanish field was averaging 23 mboed net to Whiting during Q4.  This was basically flat vs 2010.  Production in the Lewis and Clark play was 6mboed during Q4, which represented a 50% increase over Q3.  They break out “Hidden Bench” for the first time (see map bellow) with 29,000 net acres, and “Tarpon” with 6,000 net acres.  They also continued to talk up their “big tex” prospect in the Bone Springs play in the Delaware Basin Permian.

In their EOR fields, North Ward Estes production was up from 7.1 mboed in 2010 to 8.4 in 2011.  Postle Field was fairly flat at 7.1mboed.

In May of 2011 the shareholders approved a measure put forward by the board to authorize up to 300mm shares of common stock, up from 175mm previously.  The market may have taken this as a sign that they were about to issue massive new equity, and it was not taken well at all.  The borrowing base was also increased from $1.1b to 1.5b.  They also prepared for the issuing of a second royalty trust with 18mmboe of reserves.  This combined with the massive outspend of cash flow did not impress investors.

2012: Growth but with significant outspend, and an unimpressed stock market.  A year of impressive organic production growth of 22%, although they outspent CFO by $770mm to get there.  Sanish production held about flat at 32mboed. 

The company completed the IPO of Whiting USA Trust II, selling 10.061 mmboe of P1 reserves for $322mm.  $32/BOE of P1 reserves is a much better price than when they did Whiting Trust I!  If you substract the cash raised by selling the Trust, then there was really only a $440mm outspend, which is not bad for the 22% production growth.  The Trust assets were producing 4.5mboed, so if we adjust growth for this its actually about 25% yoy.  The rest of the cash shortfall was financed by increased bank borrowing.   They also sold a 50% interest in a gas processing plant in North Dakota for $66mm.

2013:  Breakout.  The stock really started to move in august based on several positive turns of events.  They sold Postle, freeing up cash for drilling.  They announced very positive improvements to frac designs in September.  They also announced a huge and highly economic drilling inventory in their Red Tail Niobrara prospect.

They announced that they are pursuing vertical targets in the NW Bakken acreage.  They expect 200 mboe per well with $3-3.5mm well cost.  This compares to typical Bakken type curves of 400-600mboe, but with well costs double.

In June they announced that they expected to be able to drill highly economic Niobrara wells in their 90,000 acre red tail prospect, 32,000 acres of which they acquired in Q2 2013.  Completed well costs will be in the $4-5.5mm for horizontal wells, with IPs of about 1000 boed.  They also announced they will be focusing heavily on this play, and the Bakken, and will put their 70,000 net acre Big Tex play up for sale.  Wells there are pricey at $8.5mm, and IRRs are lower than Bakken or Niobrara.  Although the acreage is not that big, they are planning from the get-go to do 8 wells in the B bench and 4 in the A bench per 640-960 acre section.  This is an incredible inventory of 1200 wells, will require about $6b in drilling capex to drill out the inventory at $5mm per well.

They also announced the sale of Postle for $830mm.  This is definitely good news, because it frees up capital for higher return unconventional development.

They announced in September that they had successfully issued $1.1b of 5% notes due 2019 and $800mm of 5.75% notes due 2021.  They also had done a private placement of $400mm of 5.75% notes due 2021.  The main purpose seems to be rolling over the 2014 7.5% notes.  Most of this would presumably be used to pay down their revolver, which had 847mm left of its $2.5b capacity.

They also announced that they are accumulating acreage in three new oil resource plays.

 Financial Performance:

Overall I always felt that Whiting had decent financial performance over it's first decade as a public company, but this also came partly because of a huge increase in oil prices over the period, and not just due to superior operational performance.  As I mentioned earlier, the original reason I bought them was because I considered them to be an OK run company with a low valuation.  They managed a fairly steady 15% growth in production, but also did accumulate some debt over the period to finance this.  I think we are likely to see a step change in financial performance going forward though, because of much more impressive drilling results in the Bakken, a shift from lower rate of return EOR projects, high return opportunities in their Red Tail prospect, and synergies from their combination with Kodiak.  I also think that like so many other E&Ps we may be right in the midst of a transition from constant outspend of cash flow, to a period where growth is funded generally within cash-flow, and cash may even be returned to shareholders.  E&P dividends are still very small as a percentage of cash flow or net income, and generally only the larger E&Ps like Apache and EOG are paying them.

In the next post I'll concentrated on their activity in the Bakken, their core area.

EIA July drilling productivity report out

The EIA monthly drilling report is out, and there is an interesting new feature showing YOY data instead of just MOM.  There is just so much information in these reports.  We can see how the Bakken growth does seem to have slowed a bit, even as rig productivity there continues to improve.  The slowed growth seems to have come from reductions in rig count.  The reduction in rig count could be for any one of a number of reasons.  Perhaps the majority of acreage is now HBP, so there are increases in efficiency from pad drilling.  There may be capacity and take-away constraints that some operators are running up against.  There also are rumors that there will be flaring penalties which could force the companies to put a lot more into gas collection infrastructure, and limit the pace of growth in the near term.

Also, even with an infinite number of drilling locations, production will eventually plateau as old wells decline cancels out production growth from new wells.  The production chart from any of the major plays still looks a long way off from plateau though.

I think one of the most interesting things that has happened over the past year has been the very dramatic increase in drilling productivity (as measured by EIA) in the Niobrara region.  "new oil production per rig" has basically doubled in the past year, although a portion of this could be due to increased use of horizontal instead of vertical rigs.  The Niobrara production isn't taking off Eagleford style, but it does seem like this may become a very significant region.

A brief history of the Bakken

I’m going to do a post on Whiting, like I did on Apache a little while back.  But first I want to go over a brief history of the Bakken formation in North Dakota, which is one of the big three growth areas for oil production in the USA over the last several years.

It has been known since the 1970s that there was a large amount of oil in place in the Bakken formation, with estimates ranging up to 100 billion barrels of oil in place in the early 1980s, but a lack of technology and low oil prices kept production from the formation low.  Around 2000 companies began drilling the the Elm Coulee Field at the western edge of the Bakken Formation in Eastern Montana.  This field was drilled using conventional vertical wells and production from the field peaked in 2006-2007. Around the same time, EOG began drilling Horizontal wells in the Bakken in Central Montrail County, North Dakota.  Most activity in the state centered around conventional drilling of traditional stratographic traps.

In early 2006 there was significant activity in the southwest of the state in a few conventional fields called Cedar Hills, Cedar Creek, and Little Missouri.  Burlington Resources, Fidelity Exploration, and Sequal Energy were drilling in this formation.  XTO, Whiting, Continental, Denbury, Hess, EOG, and some other independents were also active, though there were few impressive wells.  Then later in 2006 EOG drilled a well in central Montrail County in the area that would become known as the Parshall Field that would soon set off the rush to the Bakken.  EOG had applied techniques similar to those already being used to extract shale gas to a tight oil formation.  This event really was historic, and may be looked back on as a major development in the history of energy.  Not only did EOG 's discovery set off the Bakken rush, it also set off a search for other vast tight oil formations that might now be accessible.

The above map, available from an EIA.gov article from 2011, shows the areas of the Bakken that had been drilled to that point.  By far the bulk of the drilling was in the original Parshall Field region, which was dominated by EOG, and the adjacent field to the west called the Sanish field, which had been leased up mainly by Whiting.  Continental Resources was most active in the Nesson Anticline region and the Dunn County region to the south.  Using a subscription based online database called “Drilling Info”  I downloaded the images in 2012 of early well results.   The image below shows only the well results from the second half of 2011.  During this period a little over 1000 wells were drilled, and when you compare to the image to the one above, you can see that the areal extent of the region where productive wells were being drilled had expanded dramatically.

 Another way to look at the history is through the drilling results by the various companies most active in the Bakken.  Below is a great chart because it really shows a variety of interesting things.  I created this chart by downloading data from Drilling Info.  First let me explain what these numbers represent.  These show the average cumulative production of the wells drilled in the period shown on the left hand column through the date of the data download in may of 2012.  So early on there were really four active companies, all of whom had largely leased their land from the landowners directly.  In the early days EOG, who had discovered the Bakken was drilling the best wells by far.  If you want to think about the economics of these wells, you take the number of barrels produced, multiply by $100/bbl, then maybe subtract 1/3 for opex, which may be a bit conservative, and then assume the well cost $10mm to drill (although some companies were averaging as low as $7).  But anyway, you can see that the average EOG well from 2006 to 2008 had paid itself off twice over in the first five years, and still probably had considerable production left (although production does decline fast).  The average Whiting well in the very early period was a money loser, but then as the Sanish Field area got going they started making good money starting in 2008, and were even drilling the leading wells for late 2009 to 2010.  Another thing to note, is that because the production tends to be very front-end loaded, often the payback period on these wells is quite short.

Lastly, here are a few charts to lend some perspective:

North Dakota production has now topped 1mm barrels of oil per day (this chart is from EIA and is awkwardly given in barrels per month).  Currently it is the second largest oil producting state behind Texas, but ahead of Alaska and California.

 This shows the drilling rig count trajectory as of 2012.  Since then it has flattened out around that peak level.

Weekly prices as of July 18, 2014

After missing last week’s update, I’m showing price changes from the past two weeks below.  There has been quite a big sell off in E&P companies over the period, especially those most exposed to natural gas, which was down almost 10% on the nymex.  Brent crude also continued to sell off as worries about Iraq supplies receded and Libyan production looks set to increase.  The Marcellus companies  have been totally walloped, as has Chesapeake and Southwestern, all quite dependent on gas sales.

The one bright spot has been Whiting, my biggest position.  The market cheered the takeover of Kodiak at almost no premium.   The combined company should be able to realize efficiencies in their drilling program and improve their return on capital.   Kodiak has a much smaller acreage position than Whiting, but much of it is very much in the core of the Bakken.  I hope to do some posts on Kodiak/Whiting and the Bakken in general over the next few days.

Nice article on the Permian from EIA

The article talks about how the substantial majority of the production increases is coming from the Bone Springs and Wolfcamp formations in the Delaware Basin, and the Spraberry formation in the Midland Basin.

Price update

I apologize again for the inactivity, I've just been too busy.  This is the first week in a while where we've really seen energy underperform.  The Iraq situation actually seemed to improve a bit, with the government making some gains against ISIS.  This week was also notable in that there didn't really seem to be any real trends for one region or another outperforming.