Tag Archives: Chesapeake Energy

Chesapeake’s Monster Hogshooter Well

A couple months ago I wrote a piece on the biggest wells by formation and I just came across one that should have been in that group. Chesapeake’s (CHK) Thurman Horn SL #406H well, located in Wheeler County, TX, produced at a whopping 6,829 BOEPD during its peak production month. While you might be inclined to think natural gas accounted for much of the production given the area, CHK broke out the hydrocarbon production for the first 8-days as follows, 74% oil, 16% natural gas liquids (NGLs) and 10% natural gas.

Well Name: Thurman Horn SL #406H
Operator: Chesapeake
County, State: Wheeler, TX
Formation: Upper Hogshooter/Missourian Wash (9,915′)
Spud Date: May 1, 2012
Peak Month Rate Oil: 4,801 BOPD
Peak Month Rate Gas: 12,172 Mcfpd
Cumulative Oil: 497,635 BO
Cumulative Gas: 2,112,139 Mcf
Latest Monthly Rate Oil: 249 BOPD
Latest Monthly Rate Gas: 2,395 Mcfpd
Source: Texas Railroad Commission/The Energy Harbinger.

While this is a monster well and might even be responsible for the largest 30-day rate of any horizontal well ever drilled on land, there’s a few things that need to be kept in mind. First, this well is not indicative of other wells drilled in the Texas Panhandle Wash play. Most of the wells drilled in this area are much gassier and produce far less oil. In fact, even as prolific as the oil production has been in this Thurman well, it only accounted for 30% of production during its last monthly rate (compared to 70% during its peak month) which shows us that the oil decline in these wells is very high.

What this well does show us is how prolific the Hogshooter (Missourian Wash) formation can be. CHK and Forest Oil (FST) have both drilled a number of Hogshooter wells that have produced impressive amounts of hydrocarbons. If you aren’t familiar with this zone, a comparison could probably be made to the Lodgepole in North Dakota: A prolific zone in a formation that only exists in certain areas and is very difficult to target. Chesapeake itself has approximately 30k net acres it considers prospective for the Hogshooter zone.


An Early Look at Range’s Mississippian Results in Kay County

After looking at Range Resources’ (RRC) early production results in the Mississippi Lime, it’s hard for me to understand why the company thinks estimated ultimate recoveries (EUR) from its wells will be 600 thousand barrels of oil equivalent (MBOE).  I read that in their presentation, look at their estimated well cost of $3.4 million and wonder how many investors lick their chops and buy the stock.

When production results for the company’s Balder #1-30N well were released, some believed RRC had found the “sweet spot” in the Lime.  Its acreage is positioned along the Nemaha Uplift in Noble, Kay and Cowley Counties, East of where SandRidge Energy (SD) and Chesapeake Energy (CHK) have been drilling.  While the Nemaha area is shallower and oilier than Alfalfa and Grant counties, there’s also less pressure which appears to be effecting production results as shown by the graph below.

30-Day Production Rates in the Mississippian (Barrels of Oil per Day/BOPD)
Source: Production Reports / The Energy Harbinger.
*Based on 13 RRC wells

The above graph shows RRC’s limited results from Kay County compared to SD’s results across the Mississippian.  Of the company’s 13 wells which have been on production for more than a couple months, their average 30-day IP rate is 149 barrels of oil (BO) with an implied 534 Mcfpd (238 BOEPD) based on a 63% oil cut (see bottom for more on the implied rate).  These results are mediocre for the Lime and will need to improve for the company to reach its EUR goal for its program.

Now to be fair, Range is still drilling to hold its acreage, meaning the company isn’t drilling in its best areas but in a broad range of areas which it believes holds the most potential for its acreage block.  Still, when I see verbage like “17 well average EUR is 600 MBOE” on the type curve in its presentation, I’m a little concerned as to its validity.  Even if the company has a handful of wells I haven’t seen, you can look to the performance of the heralded Balder #1-30N well to see the steep oil declines associated with drilling in a low pressure formation.

Production Results from Balder 1-30N (Kay County)
RRC_Balder 1-30N
Source: Production Reports / The Energy Harbinger.
*Natural gas production data is not available to the public for wells designated as “oil wells” in the State of Oklahoma.  These natural gas production results are not the actual figures produced from the well but based on an implied rate calculated from the oil/natural gas rates in the well’s completion report.

The graph above shows the steep decline for oil which is indicative of the larger wells drilled to date in the Mississippian (see my article on SD’s wells).  While natural gas appears to decline in lock-step with oil, these are not actual natural gas figures as shown by the footnote above, but implied figures to give us a better understanding of the economics of these wells.

Regarding economics, the Balder well has produced more than 57 MBO and 134 MMcf of natural gas as of November, 2012.  This well paid for itself in its first six months of production based on a $3.4 million drilling and completion cost (includes SWD well cost).  While the Balder well is a good result, it’s the exception so far in Range’s Miss Lime drilling program which puts its economics/type curve in question.

When you look at the Mississippian as a whole, there’s big wells being drilled from Alfalfa to Kay Counties in Oklahoma in addition to Harper County across the border in Kansas.  We know there’s a lot of oil there, but it appears the industry hasn’t quite discovered the secret to producing oil from low pressure systems.  Once it does, we could have a lot of cheap oil on our hands.

The Well Map Update (2-4-2013)

I apologize for the “pump-fake” on the new well map features.  Development is taking longer than expected due to my developer’s work load, but hopefully we’ll have something soon.  I also apologize about some data inconsistencies as for a few days the integers from production values weren’t displaying in full after we moved the well map data to a new database.  These issues have been corrected.

I now have North of 2,500 wells up on the website after adding some Encana (ECA), Bonanza Creek (BCEI), Bill Barrett (BBG) and Anadarko (APC) wells in the DJ Basin/Wattenberg Field in addition to 43 Granite Wash wells drilled by Chesapeake (CHK).  All of the Granite Wash wells are located on the East side of the Texas Panhandle in Hemphill, Lipscomb, Ochiltree, Roberts and Wheeler Counties.

These wells include results from several Hogshooter/Missourian Wash wells, the most recent of which is the Stiles 67 SL #22H well which had a 29 day IP rate of 2.0 MBbls of oil and 4.3 MMcf of natural gas, a monster to say the least.  CHK has drilled quite a few wells in the Granite Wash area and I picked the oilier set for the most part.  With that said, there’s a few natural gas wells in the mix to go along with six wells which had 30-day rates of more than 1 MBbls of oil.

As many of you know, Texas doesn’t conform to the township-range-section system that the rest of the country (outside of Louisiana?) uses, so in the location box I put the formation that the well was drilled into.  The industry often refers to these formations collectively as the “Granite Wash,” but know that this is only a generalization as the Granite Wash is its own formation with the rest of these formations sharing similar geological characteristics.  The stratigraphic map below will help you fill in the blanks if you’re unfamiliar.

Granite Wash/Texas Panhandle Stratigraphic Map
Source: Forest Oil.

I’ll have more on the Texas Panhandle soon and I’ll fill in the Oklahoma side of the Wash as well.  I know a couple of you requested map data on the formation though, so I thought I’d get this up sooner than later.


Eagle Ford Production Rates by County

I apologize for not getting more information to you guys on a consistent basis.  By nature, I like to be thorough with everything I post, which leads to fewer posts but better information.  Moving forward, I’ll try to post data points such as the graph below which can be useful to you during times when I’m not writing as much.

Source: Texas Railroad Commission.
*BOPD number includes oil and condensate.

The above graph was prepared using information provided by the Texas Railroad Commission (TRC).  Based on the data I’ve looked at, Lavaca County has been the source of the highest production rates in the Eagle Ford to date.  Note that the sample size for Lavaca isn’t as large as some of the other Counties due to lack of drilling, but I would expect it to be an active County moving forward.  Also note that while Lavaca saw the highest rates, it’s also the deepest of the above counties (see table below) on average with depth to the top of pay at around 11,471′.  This implies that Lavaca is also the most expensive county to drill in.  While Webb is the most prolific Eagle Ford County on a BOE basis, its production is mostly gas and condensate.  The TRC classifies all of Webb’s production as either gas or condensate and at this point I’m assuming any oil produced from Webb is being lumped into condensate (my inquiries to clarify this issue with the TRC haven’t been successful to date).

Below is an Eagle Ford map which you can use to reference county locations.

The Eagle Ford gets oilier towards the North as shown by the red gas wells and green oil wells.  Chesapeake (CHK) drilled a number of wells in Webb County (SW Eagle Ford) between 2008 and 2010 and has since (along with the rest of the industry) focused the majority of its drilling in the formation’s oilier counties.  The best counties in the Eagle Ford appear to be Gonzales, Karnes and Lavaca, which are towards the Northeast of the play (the highlighted counties North of Fayette are an extension area which hasn’t seen much development to date).  I know EOG Resources (EOG) and Halcon Resources (HK) both have acreage in Leon County so results there will be something to pay attention to.

The table below shows depths by County as well as the operators I looked at in each county for this analysis.  The far right column shows the wells by county used in the graph above.

Drilling costs in the Eagle Ford are ranging from $6 to $9 million depending on the operator.  EOG and HK are the lowest cost producers I’ve seen in the play, with most companies spending between $7 and $9 million.  Compared to the Bakken, the wells are less expensive but also contain lower oil content.  The Eagle Ford does have several advantages over the Bakken, including smaller spacing units (EOG is experimenting with 60 to 90 acre spacing) which lead to more well locations (thus a higher recovery factor of oil in place) and close proximity to trading hubs including the St. James terminal in Louisiana where companies are currently receiving a $10+ premium to WTI.

One thing to caution with the Eagle Ford is the best acreage is probably being drilled first, much like the Parshall field in North Dakota’s Bakken.  Either way, its a monster play with a number of counties that are producing very consistent results.

DJ Basin Update (CRZO gets $4,558 per acre in JV)

EOG Resources’ (EOG) Jake 2-01H well on its Hereford prospect (Northern Weld County) put the horizontal Niobrara on the map with an average 30-day production rate of 645 BOEPD.  This well gave the industry hope that the formation could be produced economically outside of the prolific Wattenberg field.  Up until recently, results in the DJ Basin (Niobrara) had been inconsistent, with several operators drilling a number of uneconomic wells.  Chesapeake Energy’s (CHK) CEO Aubrey McClendon has called CHK’s acreage in the area “disappointing” and has since put it up for sale.  EOG’s CEO Mark Papa said the following regarding the Niobrara, “I mean it’s no secret that the Niobrara is proven to be one of the more complex horizontal oil plays that both we and the industry have dealt with.”

Why is it so hard to drill in the Niobrara?

For starters, when people talk about the Niobrara they’re probably referring to the DJ Basin but know that the formation spans several states and several basins (see map below), including the Green River Basin (NW Colorado), North Park Basin (North-Central Colorado), DJ Basin (NE Colorado) and Powder River Basin (Eastern Wyoming).  While producing intervals will vary across these basins, I’m going to focus on the geology of the DJ because most of the Niobrara’s development has emanated from this basin to date.

Sources: Colorado School of Mines; Colorado Geological Survey

As you can see from the stratigraphic column above, the DJ Basin is characterized by three benches (A, B and C) which are primarily composed of chalk that have been compressed over time, thus having low permeability.  These benches are separated by three marl/shale zones that contain high clay volumes (virtually no permeability) making it very difficult/expensive to frack a well through all three zones as the clay blocks commingling.

Drilling into the benches separately is no easy task either as they are relatively thin.  The “B” bench is the thickest, ranging from 20’-40’, making it difficult for operators to stay in zone.  Complicating matters is faulting throughout the Basin which thins the intervals in certain areas.  Imagine fracking into a zone 7,000′ deep  that may be no wider than 10′.  The FT Hays Limestone, Codell Sand, D-Sand and J-Sand are also prospective for hydrocarbons throughout the DJ Basin, creating a series of stacked pay zones for operators to explore.

What the DJ Basin does have a lot of is oil and natural gas.  Nearly two billion barrels of oil equivalent (BBOE) has been produced from the Wattenberg field alone and sell-side investment bank Tudor, Pickering and Holt (no relation) estimate the basin holds an additional 4-10 billion barrels of recoverable oil and gas.  This isn’t just a Niobrara story either, as the D and J-Sands alone have produced approximately 1 BBOE to date.  The basin also gets oilier as you move North too, with 90% oil cuts in EOG’s Hereford prospect.  The big question is how to get to it economically.

(See TPH’s Niobrara Primer here, it’s a great resource which I relied on for this report)

One of the keys to producing from the Niobrara is to find areas where it’s naturally fractured, which increases the operators margin for error when drilling the chalk, but could also fracture the marls/shale, allowing for commingled production from the Niobrara benches.

The Wattenberg field has been economic for decades, in part because natural fracturing exists throughout the field.  What companies must do outside of the Wattenberg is either find areas with natural fracturing or induce fracturing themselves.  This is not only expensive (well costs are $1.0 to $2.0 million more outside of the Wattenberg), but well production outside of the field has been no more prolific and much less consistent, leaving operators like Chesapeake and GMX Resources (GMXR) to abandon the play.

So where are we at in the DJ Basin today?

EOG Resources

EOG has ramped-up production in the play since 2010, drilling more than 50 wells and producing more than 3.0 MMBbls of oil and 4.0 Bcf of natural gas.  The bulk of the company’s production has come from its Hereford ranch prospect, lying in Northern Weld County, where it holds approximately 80,000 net acres.  After evaluating its well results, EOG decided the DJ Basin would be an ancillary project for the company as its economics didn’t rival those of its other plays.  Consequentially, the company hasn’t done much in the basin since 2011 and has quit talking about it in its presentations.  Who could blame them really? EOG has the best acreage in the two best unconventional oil plays on the planet.

Just how economic were EOG’s wells in the DJ?  I took a look at ten different wells in its Hereford prospect and found an average 30-day IP rate of 348 BOEPD.  I then selected six wells from different quartiles of this sample size and looked at 80-90 day rates from these wells (see table below).  While I included gas production in the table, EOG flared nearly all of its gas from these wells, so I didn’t include it in the economics.

Source: Colorado Oil & Gas Commission

These wells were all drilled by EOG between 2010 and 2011.  This data shows us that after 86 days, EOG’s average well will produce approximately $2.3 million in revenue (at $90 oil) or 42% of the overall cost of a well (again this doesn’t include gas production).  These Hereford ranch wells show low decline rates during the first year, making them economic; however, not nearly as economic as the wells the company is drilling in the Bakken and the Eagle Ford.  One would think an experienced Niobrara operator like Noble Energy (NBL) would be interested in this acreage.

So Chesapeake and GMXR have thrown in the towel and EOG is largely on the sidelines, who else is trying to figure out the Northern DJ Basin?  The aforementioned Noble Energy.

Noble Energy

Noble’s onshore U.S. legacy assets are in the Wattenberg field, so the company is familiar with the complexities of drilling in the Niobrara.  NBL currently holds 410k net acres in the Wattenberg and 230k net in the Northern DJ.  Its decision to divest non-core assets in the Permian, mid-continent and North Sea earlier this year to focus more on the Niobrara and various international plays certainly gives the play a boost of confidence.  To combat the Niobrara’s various complexities, the company has been experimenting with spacing units down to 40-acres on its horizontal program, in addition to an extended reach lateral program where it’s drilling 9,000 foot laterals.

Noble is seeing better results on its 40-acre spacing program, with the theory that smaller spacing units are breaking up more rock which is increasing permeability.  Its first extended reach lateral (unclear where this was drilled) cost $7.5 million and averaged 400 BOEPD during its first year of production.  NBL expects it to produce 750 MBOE, a success that has the company testing more of these wells moving forward.  The company has already spud more than 190 horizontal wells (40 in Northern Colorado) this year using seven rigs and will add three more rigs by year end.  It’s experimenting with pad drilling as well, which should lead to decreased well costs, providing a boost to the economics of the play.

In the horizontal Wattenberg, the company expects EURs to range from 337 to 350 MBOE based on 30-day average IP rates of 497 to 567 BOEPD (60-80% liquids).  What’s more encouraging for the Niobrara itself is that NBL is seeing improved production results on its last eight Northern Colorado wells with 30-day average IPs of 550 BOEPD (85% liquids) which track an EUR of 310 MBOE.  Don’t hold your breath on these results just yet, as the Northern Niobrara is proving to be about as hard to tame as Afghanistan, but there’s a lot of oil there so they’re worth keeping an eye on.

Anadarko Petroleum

Anadarko (APC) recently pledged to spend $1.0 billion annually during the next several years developing its Niobrara acreage.  In the DJ, the company currently holds 350k net acres in the Wattenberg and 550k net acres to the North.  The company plans to drill 170 Wattenberg wells in 2012, 270 in 2013 and 300 in 2014.  Based on its type-curve, a well that has a 24-hour IP rate of 800 BOEPD will produce an EUR of 350 MBOE and return 100%.  To date, Anadarko’s production has averaged right around its type-curve, and judging from its expected ramp-up, the company seems excited about the play.

Outside of the Wattenberg, Anadarko plans to evaluate its acreage by drilling 30 wells during 2012.  As of November, 2011, APC had drilled 15 wells in the area which produced at an average 24-hour rate of 350 BOEPD.  It’s difficult to read too much into those IP rates, as wells outside the Niobrara have been known to either decline slow or fall off the map.  It’s worth noting that the company has stopped highlighting this acreage in its presentations, which leads me to believe it hasn’t been all that happy with the results.

Carrizo Oil & Gas

Carrizo Oil & Gas (CRZO) just sold 18k net acres Northeast of the Wattenberg for $4,558 an acre, a great value for an area that has struggled to produce consistently.  Pro-forma to the acquisition, the company has 43,400 net acres remaining in the DJ Basin.  To be honest, I wasn’t even planning on looking at CRZO’s production data for this report, but the valuation they received intrigued me.     The company hasn’t hit any big wells on its acreage, but its 30-day average production rate of 289 BOPD (353 BOEPD) is comparable to EOG’s Hereford prospect.  Flaring has decreased on its wells, leading me to believe the company is getting gas pipeline infrastructure in the field as well, which will help the economics.  With a target well cost of only $3.6 million per well, this acreage looks to be more economic than EOG’s.

Source: Colorado Oil & Gas Commission


There’s several other companies, including Bonanza Creek (BCEI) and PDC Energy (PDCE), who are achieving solid results in the horizontal Wattenberg play, but by now you get the point: companies are excited about the Wattenberg, while the Northern portion of the play seems more prospective; however NBL and CRZO’s results in the Northern portion of the play are encouraging. The Niobrara probably won’t blow your socks off, but if you know how to work this sometimes perplexing play you can find economic oil.

Is a Natural Gas Price Recovery Coming Soon?

I’m unabashedly bullish on natural gas, but admittedly have no clue when prices are going to recover. There’s probably not a better sure fire, or as Warren Buffett would say “fat pitch,” investment opportunity right now than natural gas. Shall we go through the pro’s of the energy source again? It’s relatively clean and cheap, it’s plentiful and we have the infrastructure already in place to take advantage of it. The world’s energy needs are growing and with the prospect of LNG on the back burner, it could be a globalized commodity sooner than we think. Getting back to the premise of the article, let’s take a look at where natural gas prices have been to get a handle on where they’re going.

Natural gas prices peaked at over $10.00 per Mcf in the summer of 2008, several months after the stock market crashed and the global recession began. The graph below makes it easy to see why natural gas prices crashed: production increased supply and without a demand increase to offset the supply increase, prices began to decline. Ok well, why did production continue to increase in the face of declining natural gas prices? Most of the answer is the Marcellus shale, the rest of the answer is increased production of associated gas in oil shale plays (ie: Bakken in North Dakota, Eagle Ford in South Texas). Companies like EQT (EQT) are able to receive 53% IRRs in the Marcellus at $4.00 gas and ~20% returns at $3.00 gas, well above returns earned in other prolific shale gas plays such as the Haynesville. Therefore, they’ve little incentive to stop drilling until gas prices drop below a point at which IRRs earned are unacceptable for shareholders.

Historical Natural Gas Production and Prices (January, 2008 to May, 2012)

Source: EIA

Fortunately (or not) for natural gas companies who aren’t so lucky to have large acreage positions in the Marcellus, natural gas prices have been below $3.00 per Mcf for more than six months, and that $3.00 mark seems to be scaring the Marcellus crowd. One of the market’s first big clues that operators weren’t going to drill through sub $3.00 gas was when Chesapeake Energy (CHK) released its 2012 Operating Update in late January, 2012. In the update, CHK announced it was going to decrease its natural gas rig count 50% to 24 rigs by Q2’2012, in addition to decreasing its 2012 natural gas drilling budget $1.2 billion. While low natural gas prices weren’t exactly a “newsflash” in January, news that the second largest North American natural gas company was cutting back to this extent was a big deal.

As the graph below shows, it’s not just Chesapeake that’s cutting back on natural gas, but an industry wide trend that will undoubtedly lead to lower future production numbers. Since peaking at 116 in August of 2011, rig counts in Pennsylvania (location of Marcellus Shale) have declined approximately 41% to 68 as of August 17, 2012 according to data provided by Baker Hughes (BHI). Even more telling is the Unites States’ oil/natural gas rig count split. At the beginning of 2008, natural gas dominated this statistic, accounting for 82% of total rigs (see graph below) in the U.S. . By August of 2012, this number had declined to 25% and was down 15% (from 40%) during the calendar year.

U.S. Rig Count (2008 to 2012)

Source: Baker Hughes

We know that a large part of the natural gas price problem is oversupply and that natural gas rig counts have been in decline for the past year, so why haven’t natural gas prices started to rebound? For starters, rig counts in the Marcellus didn’t fall below 100 until April of this year, but quickly fell to 68 by August. So we shouldn’t start to see natural gas production declines until later this year. A second factor is associated gas from oil shale plays. In North Dakota during June, natural gas production increased 86% year-over-year to 13.6 Bcf. Another bearish sign is that the production number I cited for North Dakota is production sold. The state actually produced a figure closer to 21.4 Bcf in June, as much of the Bakken’s production is flared into the atmosphere (over $17 million worth per month at $2.50 gas). For perspective, the U.S. currently produces an average of 2.0 Tcf of natural gas each month, so even if all of North Dakota’s production was sold, it would still only equate to 1.7% of total U.S. production.

Where does this leave us? Even though low natural gas prices is an old story, rig counts have only recently began to decline. It may take a few months for production to decline meaningfully enough to have an impact on natural gas supply. During 2011, the U.S. produced 23 Tcf of natural gas and consumed 24 Tcf. The country imported an estimated 3.5 Tcf (mostly from Canada) and exported 1.4 Tcf to Canada and Mexico. What this leaves us with is an oversupply of natural gas in the United States of an estimated 700 Bcf. The more companies cut into this supply glut through decreased production, the higher prices will go. Look for gas prices to range between $3.00 and $4.00 per Mcf next year, with long-term upside coming from more favorable supply and demand factors and LNG.

A Peek Inside the Hedge Books of Natural Gas Companies

If you’re a value investor who’s interested in commodities, natural gas weighted companies are probably a tempting trade for you.  The commodity itself is trading at a 35.4x discount to oil, well above the 6.0x discount predicted by energy equivalency, which means companies producing it are selling it at record low discounts and generating very little cash flow per Mcf of gas sold (versus barrel of oil equivalent sold).  If I’m going to throw my chips in on an undervalued natural gas company, I have a lot to choose from, so I might as well pick one that’s responsibly managing its price risk.  Just as I wouldn’t want to sacrifice upside potential by picking a company who’s over-hedged, I wouldn’t want exposure to a company with high debt levels and little price protection.  I believe price protection is important, because most companies aren’t experts at predicting commodity prices.  Hedging allows them to focus their efforts on what they do best: exploration and production.

The table below shows how four natural gas weighted companies have chose to hedge their gas production during the second half of 2012:

1Hedges in place as of 6/30/2012

2 Average fixed price of swap agreement from July 1, 2012 to December 31, 2012

3 Percent of Q2’12 production

4This price reflects the fixed price of EQT’s swap agreements which represent 52% of its production.  The company also has collars on 9% of its production with average floors of $6.51 and ceilings of $11.83

The following paragraphs will take a deeper look into each company’s hedging programs:

Bill Barrett Corporation (BBG)

For the remainder of 2012, Bill Barrett has hedged 34.2 Bcf (~64.8%) of its production volumes at a fixed price of $4.09 using fixed-for-floating swaps.  As an equity analyst, the first question you should be asking yourself is what does this mean?  Well, what’s probably happening here is, at certain dates between July 1, 2012 and December 31, 2012, BBG will “swap” payments with a financial institution in the following manner: The company will receive a fixed price per Mcf of natural gas on a notional amount of production and pay a floating price on a notional amount of production as shown in the hypothetical example below:

January 01, 2011: BBG enters into a fixed-for-floating natural gas swap with Barclays during a time which Henry Hub spot prices were at $4.37.  The swap states that Barclays has agreed to pay BBG $4.09 per Mcf for 34.2 Bcf of natural gas on December 31, 2012; while BBG has agreed to pay to Barclays the Henry Hub spot price on December 31, 2012 for 34.2 Bcf of natural gas.  On December 31, 2012, the price of natural gas has declined to $1.94 and BBG sells all of its production at that price, grossing $102.4 million.  What the swap does is offset the realized decline in natural gas prices of $2.43: BBG receives $4.09 * 34.2 Bcf from Barclays and sells $1.94 * 34.2 Bcf, netting $73.5 million (no production is exchanged in a swap).  So, BBG effectively received $175.9 million from selling 52.8 Bcf of natural gas at an implied price per Mcf of $3.33 despite natural gas spot prices of $1.94 per Mcf.

Is BBG currently well hedged? I would say so.  They have 64.8% of their expected 2012 production hedged at a fixed price that is well above current natural gas prices.  Looking forward, the company has natural gas swaps in place for 2013 and 2014 as well at fixed prices above $3.50 per Mcf including a 41% increase in volumes hedged for 2013, allowing the company to continue to receive downside protection if natural gas prices remain low; however note that BBG’s upside would be limited if natural gas prices spiked.  The company’s stock has been hammered hard during the past year in response to low gas prices, so this might be a good time to buy low with confidence that the company’s hedge program is responsibly managed.

Chesapeake Energy (CHK)

While Bill Barrett is well hedged for 2012, Chesapeake had no hedges in place for the first half of 2012, before entering into two swaps for the second half of the year covering 38.7% of its production at low average fixed prices of $2.97 per Mcf.  CHK has written a number of out-of-the-money call options (average strike prices are $6.05) on 169 Bcf of production that expire during the second half of 2012 and have virtually no chance of being exercised, but premiums for these options were received in prior years meaning they will not affect this year’s cash flows.  Even if these options were written this year, they’re so far out-of-the-money that they wouldn’t have fetched much of a premium.

What happens if natural gas prices spike and these options are exercised?  Well for starters, a call option gives the holder the right (but not the obligation) to purchase an asset during a designated period in the future.  The asset is delivered by the option writer, Chesapeake in this case, so CHK would have to deliver the contracted amount of natural gas at the exercise price.  This would effectively lower CHK’s price received as it could have alternatively sold said production in the market at the prevailing spot price which (in this situation) would be more than the exercise price.

Chesapeake’s virtually un-hedged natural gas position combined with low gas prices caused its operating cash flows to decline 62% year-over-year during the first quarter, hurting the company’s ability to finance its 2012 capital budget and contributing to its continued stock price decline.  The company’s decision to not hedge this year was probably due to the belief that natural gas prices would recover and/or unattractive hedging options due to a low natural gas price outlook.  While CHK’s increased liquids production will help its cash flow issues in the future, it’s still highly levered to natural gas prices, which coupled with high debt levels could spell future trouble.

Cabot Oil and Gas (COG)

Cabot is an interesting story because despite low natural gas prices and a moderate hedge program considering its weight towards natural gas, its stock has performed well (currently trading near the top of its 52-week range) thanks in part to an analyst upgrade from JP Morgan.  COG’s stock performance is puzzling because its average natural gas price received declined 25% to $3.52 year-over-year during the first six months of 2012, and this story shouldn’t change much over the balance of the year.  Maybe the market is anticipating a bump in realized prices per BOE after its oil/liquids production from the Eagle Ford comes online.  I will admit that the company has a world class asset in the Marcellus and its IRRs aren’t bad at $3.50 gas. In addition, the company’s hedge book looks strong in 2013, with a floor at $5.15 on 17.7 Bcf of natural gas production.  Either way, I’d use caution before investing in this stock unless you have a longer holding period.


EQT is your quintessential Marcellus company, with 100% of the company’s production coming from Appalachia and a responsible hedge rate of 60.5%.  The company is trading just shy of the middle of its 52-week range, after increasing 29% from its low to $56.45 per share at market close on August 16, 2012.  Did you miss the boat on EQT? I don’t think so for this reason: The company’s average realized sales price was 32% lower year-over-year at only $3.83 per Mcfe during the second quarter.  For the second half of 2012, the company has a floor of $6.51 on 11 Bcf  or 9% its production and average fixed prices on swaps of of $4.67 on 66 Bcf or 52% of its production.  Moving into 2013, the company has a floor of $4.95 on 25 Bcf of its production and a fixed price on a swap of $4.91 covering 84 Bcf of its production.  This strong hedging program should improve the company’s realized prices substantially.

Ok so what are these “floors” companies keep mentioning?  The hedging instrument EQT is using, in addition to its fixed-for-floating swap, is a “costless collar.”  This particular collar is a series of short positions in caps called caplets which “cap” the price you would pay for an Mcf of natural gas by paying off if the price of natural gas rises above the strike price (similar to a call option), counterbalanced by a series of long positions in floorlets  which would payoff if the price of natural gas falls below the strike price (similar to a put option).  In this way, the price received from production is kept within a range equal to the floor price and the ceiling price.  The collar is “costless” because the company uses the option premium from the short position in the cap to pay for the long position in the floor.

Other thoughts?

The investment analysis I provided on these companies is far from complete and I’m really only giving recommendations based on recent trading trends and my view of their respective hedge books.  What I’m hoping you get out of this post is some investment ideas to go along with a clearer picture of what a company is talking about when they mention derivatives or hedging.