Monthly Archives: August 2012

After its Bakken Acquisition, is QEP Fairly Valued?

Like many natural gas companies, QEP Resources’ (QEP) stock price has struggled during the past several years.  Since peaking at $45.20 on July 26, 2011, the company’s stock has tumbled 36% to $28.80 at market close on August 24, 2012.  Also like many natural gas companies, QEP has been looking for ways to increase its oil/liquids production cut in response to a depressed natural gas price environment.  For the most part, the company’s transition to liquids production has occurred internally, with a shift in focus to the liquids portion of its midcontinent acreage, the continued development of its legacy Bakken acreage and the completion of its Black Forks II NGL processing plant in Wyoming.  QEP recently proved it’s not opposed to making a bold acquisition in an oil play and did so by spending $1.38 billion to acquire 27,600 net acres in the Bakken, bringing its total to 118,000 net acres in the play.

While the company’s shift to liquids may seem like a logical move for a natural gas company at present, it’s an expensive endeavor and not without risk, just ask Chesapeake Energy (CHK) and GMX Resources (GMXR) who’ve both experienced financing difficulties during their respective transitions.  Of course, both CHK and GMXR were highly levered before they bought into oil plays, leaving them with inadequate cash flow to finance their capital budgets.  By contrast, Permian operator Approach Resources (AREX) emerged from its transition to oil with minimal debt and has subsequently had success developing its assets.  So where does QEP stand amongst these companies?

Pre-acquisition, the company had a responsible debt-to-market cap of 36.3% and an interest coverage ratio of 13.1x.  QEP financed the Bakken acquisition with its credit facility, increasing its debt level 68% to $3.2 billion in the process.  Its debt-to-market cap ratio increased to 61.5% (see table below) and its interest coverage ratio declined to 10.3x.  The company did mention in its acquisition conference call that it plans to deleverage soon; however unless deleveraging comes in the form of a large divestiture this process will take some time.  In the near-term, we have a highly levered company whose production was 80% natural gas during the six-months ended June 30, 2012.

Note regarding calculations: LOE, G&A and DD&A margins were computed as a percent of sales

While QEP is highly levered, it’s a well-run company that’s both cost-effective and adept at extracting cash flow from its production.  The company’s LOE margin is average for its peer group, but its G&A and DD&A margins are actually lower.  Its cash margin of $4.07 ranks second in its peer group, indicating the company is efficiently extracting cash flow from production despite its leverage to natural gas.  It’s worth noting that QEP’s costs have been trending up as the company has increased its liquids production cut (the main culprit is transportation and handling costs) and this will be something to monitor as the company continues its transition to liquids.  Its cash margin improved to $4.17x during this span, but will take a hit post-acquisition due to higher interest payments.

Effect on Credit Facility

QEP was undrawn from its $1.5 billion credit facility prior to this acquisition which will draw approximately $1.4 billion.  The company paid 2.05% on its credit facility draw during the first half of 2012, which translates to an increase in quarterly interest payments of $7.4 million ($29.5 million annually) based on its new balance.  By my estimation, QEP will still have a strong interest coverage ratio of 10.3x post-acquisition.  Approximately $55 million remains undrawn on the facility at present; however the company does have an option to increase its draw to $2.0 billion.  The facility matures in 2016 with options to extend to 2018, presumably at a higher interest rate.

Considering low gas prices and high financial leverage, should we be worried about QEP’s ability to finance its capital expenditures? The company will be getting a modest bump in oil production of 10.5 thousand barrels of oil equivalent per day (MBOEPD) from its Bakken acquisition.  This has bumped the company’s full year production guidance by 5 Bcfe (midpoint of guidance) or 833 MBOE which translates to a $20.4 million increase in operating cash flow (assuming current cash margin) by the end of 2012.  During the six-months ended June 30, 2012, operating cash flow was $694.3 million.  If the company keeps its current production (including new properties) flat, I estimate QEP will generate $1.5 billion in operating cash flow for 2013.  If the company keeps its capital budget at $1.525 billion in 2013 (the company will announce guidance at its Q3 conference call), it will have a budget shortfall of $25 million.  Now QEP increased operating cash flow by $66 million year-over-year during the six-months ended June 30 despite low natural gas prices.  With more liquids production coming online during the next year, operating cash flow should continue to increase.  I do expect the company to divest assets during the next year to relieve its financial situation, and spinning of its low-margin marketing arm might make some sense.

QEP’s reserves prior to the Bakken acquisition were 76.1% natural gas and had a reserve life of 13.1 years.  The company has been steadily growing its oil percentage from reserves to 76.1% from 91.9% in 2009 and has done so at a strong three-year finding and development cost of $1.75 per Mcf.  QEP added 125 MMBOE of proved and probable reserves with the transaction (81% oil, 9% NGLs, 10% natural gas) and didn’t break-out the proved and probable split, meaning the market doesn’t know how the company should be trading on an EV/Reserve basis post transaction.

One thing we do know is that QEP’s reserves are going to get even oilier over the next year for the following reasons: 1) 91% of its capital budget was spent on liquids plays in 2012, meaning the company is investing to increase its production and proved reserves from these plays 2) QEP plans to grow its rig count in the Bakken to eight rigs by next year from three currently, meaning more rigs and capital will be spent in oil plays moving forward.  What does this mean for the company’s valuation?

Pre-acquisition, QEP was trading at a slight premium to the peer group on a production basis and a 14% discount on a reserve basis.  Based on the trading multiples of these peers, QEP should have been trading at a share price of $31.64 or 10% higher than on August 24, 2012 when its stock closed at $28.80.  If we give the company credit for daily production from the new assets and 50% of its proved and probable reserve total (62.5 MMBOE) while adjusting EV accordingly, I find QEP should be trading at a share price of $28.03 or 3% lower than the company’s stock closed at on August 24, 2012.  So where does all this leave us?

QEP’s current value is being muted by two factors: its high debt level and uncertainty surrounding the reserves associated with its new Bakken acquisition. In spite of paying a premium for the Bakken acreage, I believe the company has the liquidity available to finance its capex; however it will need to monetize an asset to pay down its debt levels. I believe $28.03 represents a floor for the company moving forward and if it’s able to reduce its debt to pre-Bakken aquisition levels, I estimate a target share price of $35.28. QEP is setting itself up to have a balanced portfolio of oil and gas assets with plenty of upside once natural gas prices recover.

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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 (EQT)

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.

High Energy Costs have Asian Companies Investing in North American Oil and Gas Plays

One of the more intriguing stories that I’ve been following over the past year or so is East Asia’s entry into North American oil and gas plays.  In college, my history teachers told me the next war would be over oil, which makes logical sense: the world runs on oil, oil resources are dwindling, and eventually there will be a violent scramble to shore up those resources so that countries can continue to function without an expensive energy revolution.  I don’t want to jinx this situation, but to this point my teachers are wrong and we can all thank capitalism and low natural gas prices in North America.

Low gas prices in the United States have gas-weighted American companies scrambling for financing alternatives to cash flow their transition to oil and liquids plays.  Asian companies, prodded by their governments, have had a healthy appetite for interests in these plays as they look to boost oil and gas reserves.  So what’s been happening is North American companies have been entering joint ventures with Asian companies to help develop their extensive land positions across various hydrocarbon plays.  In return, Asian companies are getting oil and gas production/reserves and the operational experience that comes with working alongside some of the best operators on the planet.

The following table lists the fifteen deals I’m aware of between North American and Asian companies:

1DJ Basin and Powder River Basin in Northeast Colorado and Southeast Wyoming

2Deep Basin (Cardium, etc)), Montney Shale, Duvernay Shale

3Tuscaloosa Marine Shale, Niobrara, Mississippian, Utica Shale, Michigan Basin

4Syncrude (oil sands), North sea (UK), Northeast British Columbia Shale Gas (Liard, Horn River, Cordova), Deepwater Gulf-of-Mexico, Usan (Nigeria)

As you can see from the above table, the earlier deals concerned the Marcellus Shale but prolonged low natural gas prices have shifted interest towards oilier plays, primarily in the Eagle Ford.  Acreage multiples across these deals have been very high, averaging $12,631 per acre with a combined investment of $33.1 billion.  I would guess these high multiples stem from high energy costs in Eastern Asia which has led to pressure on these companies from their respective governments to get deals done.  There’s plenty of reason for Asian governments to be concerned, as China recently surpassed the United States as the worlds largest energy consumer and gas prices in Japan averaged $14.73 per million british thermal units (MMBTU) in 2011, $10.72 more than prices at Henry Hub.  Once companies acquire reserves and production from foreign plays, they can help alleviate supply constraints by selling the production at trading hubs back home.

The Chinese are not only getting reserves and production from investing in North America, but the operational expertise it needs to help develop its shale back home.  According to the EIA, China, the world’s largest energy consumer, is sitting on more than 1.2 quadrillion cubic feet of natural gas in place which could produce the same amount of energy as 200 trillion barrels of oil.  For comparison purposes, the EIA estimates the U.S. has 862 Tcf of gas in place.   Now only a fraction of that total is recoverable using today’s drilling techniques; however it’s a significant energy source if only China’s companies knew how to extract it.  It’s no coincidence that Sinopec and CNOOC chose to participate with Devon and Chesapeake, two of the most experienced shale gas operators on the planet.

China’s investments aren’t limited to shale plays either, as they have been building a substantial reserve base in Canada’s tar sands since at least 2005.  In addition to CNOOC’s acquisition of Nexen who owned 7.23% of Syncrude, an Athabasca oil sands joint venture,the company invested a combined $2.8 billion by investing in Canadian tar sands companies MEG Energy, OPTI Canada and Northern Cross (Yukon).  Sinopec bought out ConocoPhillips’ 9.03% stake in Syncrude for $4.65 billion in April, 2010.

I don’t want to make it sound like Asian companies are only investing in North American companies either, as many of them have interests all over the globe.  But North America provides a culture of low government risk and an opportunity to diversify assets away from areas such as the Middle East.  Currently, Eastern Asia is investing billion in oil and gas, I know a lot of African companies are looking at solar as a viable source of energy.  It will be interesting to continue to follow this story as the governments of the world look for ways to meet their growing energy needs.

The Mississippian Lime: America’s Next Big Resource Play?

There’s no doubt that shale plays are sexy in the oil and gas realm these days, but prudent investors know all that really matters is return on investment.  Valuations are high in South Texas’ Eagle Ford Shale, where private equity firm Kohlberg, Kravis, Roberts & Co (KKR) recently agreed to pay $25k per acre in a participation agreement for up to 1/3 of Comstock Resources’ (CRK) undeveloped Eagle Ford acreage.  In North Dakota’s Bakken Shale, Bakken pure-play Kodiak Oil & Gas (KOG) paid $11,800 per acre in a deal late last year with two private companies.  If investors are looking for a value play, they should turn their heads to the Mississippian Lime, where acquisition prices averaged $3,284 per acre1 during the past year.

Source: Orion Exploration Partners August, 2011 Mississippi Lime Presentation

The Mississippian Lime, located in South-central Kansas and North-central Oklahoma (see map above), is a shallow carbonate play (mostly Limestone) with depths ranging from 3,000’ to 6,000’.  The Lime is not a new play, but an old producing field with more than 30 years of production and 14k vertical wells drilled.  It’s now being redeveloped using horizontal drilling and fracking techniques, and in that respect could be compared to the Permian Basin of West Texas.  While conventional production in the play stemmed from the “Mississippian Chat,” a reservoir with high porosity and permeability above the Lime, new development is targeting the tighter Mississippian Lime that underlies the Chat (see cross-section below).

Mississippian Lime Cross-Section

Source: Range Resources Corporate Presentation

Because the Lime is shallower than the Bakken and Eagle Ford, companies use smaller drilling rigs and cheaper proppants which has led to drilling and completion costs between $3 and $3.5 million, less than half of what an operator would pay in the Bakken or Eagle Ford.  The play is estimated to span 17 million acres with oil in place estimates ranging from 5.4 to 5.9 billion barrels of oil equivalent (BBOE).  This impressive amount of oil in place has companies like Sandridge Energy (SD) drilling three wells per section, which increases the recoverable reserves in the play.  For a more complete view on the Lime’s economics, let’s take a look at its most experienced operator, the aforementioned Sandridge Energy.

An intelligent discussion on the Mississippian Lime can’t be had without talking about Sandridge, who has drilled 382 horizontal wells or 44% of the total horizontal wells drilled in the play.  The company has amassed 1.7 million net acres in the Lime, from which it expects to generate estimated ultimate recoveries (EURs) of 456 thousand barrels of oil equivalent (MBOE) per well.  These EURs are based on 30-day average IPs of 275 barrels of oil equivalent per day (BOEPD), or put another way, a well that produced at an average rate of 275 BOEPD for 30-days is expected to produce an EUR of 456 MBOE.  How does this model out on a return basis?  SD estimates that a well which produces at a 30-day average rate of 244 BOEPD will have an 80% rate of return (ROR), a solid rate for a company whose average 30-day production rate is 325 BOEPD per well (119% ROR).  The table below shows how SD’s EUR estimate in the Lime compares to those of operators in other prolific plays in the U.S.

Play Economics

1Includes liquids content which prices at a discount to oil

As you can see from the table above, the Mississippian is by far the cheapest formation to produce from with respect to the peer group.  It’s worth noting that EOG Resources (EOG) and Continental Resources (CLR) are two of the premier operators in their respective plays and  if you were to take a survey of average well costs across those plays, I would expect current costs to average between $7 and $10 million per well.  The Mississippian is a play that produces more hydrocarbons per dollar than any of the above mentioned plays, with the main negative being a lower oil cut.  Despite its lower oil cut, SD is still reporting an average rate of return of 119%, a rate that has plenty of natural gas pricing upside.  The Lime also gets oilier as you move from East-to-West, and SD has reported several wells in Alfalfa County, Oklahoma with 30-day production rates in excess of 2,000 BOEPD (90%+ oil cut).  So while it’s a gassier oil play than some would like, oil cuts vary and returns are high.

These numbers aren’t going unnoticed by the oil and gas industry, but have prompted industry titans such as Chesapeake Energy (CHK), Apache (APA), Devon Energy (DVN), Encana (ECA) and Repsol (REP) to accumulate large acreage positions in the play.  CHK has approximately two million net acres in the Lime, making the play its top liquids play by acre and a key component of its shift towards liquids production.  The company plans to run 22 rigs in the Lime versus 30 in the Eagle Ford and 10 in the Utica during 2012, meaning this struggling company has levered itself to these three plays to resurrect its share price (down 73% from its high of $69.40 in July, 2008) and pay down its high debt levels.  Acreage positions of other large caps in the Lime: APA: 580k, DVN: 545k, ECA: 360k, and REP: 363k (see map below).

Range Resources (RRC) made its excitement for the Lime obvious during its second quarter earnings call, affirming its decision to market its Ardmore Woodford acreage to help finance the acceleration of its Mississippian development.  On the call, Jeffrey Ventura, President and CEO of RRC said regarding the planned divestiture, “Although the rate of return in the Ardmore Woodford is very good, the rate of return in our horizontal Mississippian play is even better.”  RRC’s excitement stems from two gushers it recently hit in the play, one which peaked at 1,363 BOEPD and a second which peaked at 1,950 BOEPD.  The company hit these wells after modifying its drilling and completion techniques by lengthening its laterals and fracs to 3,468’ and 17 stages versus 2,197’ and 12 stages previously.  For that reason, keep in mind that this is still an emerging play in its beginning stages with upside potential as companies tweak their completions.

Who’s where in the Lime?

Source: Map data was prepared based on public data provided by companies.  Please note that this map is only meant to show the acreage location of certain operators and no precedence is given to companies based on format or color.

The above map (prepared by The Energy Harbinger) shows where certain operators own acreage by county.  Because not all operators have disclosed where they’re operating and some companies have only partially disclosed the counties they operate in, this map is incomplete.  However, it does show the extent of the play and some of the more popular counties.  Net acreage by operator: APA: 580k; Atlas: 7.25k; Chesapeake: 2,000k; Devon: 545k; Equal: 7.25k; HK: 45.28k; Range: 152k; Sandridge: 1,700k.

Now we know the big operators that are in the Mississippian; however, there’s plenty of smaller companies with large acreage positions there too, including Petro River Oil.  This private company is interesting not only because it has amassed 100k net acres in the Lime, but because of its strong leadership team.  The company boasts two CEOs, Daniel Smith and Ruben Alba, who combined have several decades of experience in the oil and gas industry.  Mr. Smith has experience growing companies to maturity, serving as the Operations Engineer at XTO Energy before it was bought by Exxon Mobil (XOM) in December, 2009.  Mr. Alba brings an extensive oil service resume to the company.  Not only has he spent the majority of his career working for Halliburton Energy Services and Superior Well Services, but he also holds several patents in completion technology.  These Co-CEOs are supported by Luis Vierma, who spent several decades at Venezuelan state-owned oil and gas company PDVSA, where he served as the VP of Exploration and Production.  Bottom line, if there’s a private company to keep an eye on in the Lime, its Petro River.

If one of the negatives on the Lime is its lower oil cut, a second would be its high water content.  Sandridge is reporting an average of 2k to 3k barrels of water per day during the first 30-days of production per well.  To efficiently dispose of this water, companies must develop a network of salt water disposal wells (SWD) which they will inject produced water into for disposal in the Arbuckle Group formation (see Mississippian cross-section above).  While SWD wells add complexity to the Lime, they are relatively cheap to drill (~$265k per well) and will service water for between six and eight producing wells.  If we divide $265k by six (low end of estimate), we find that SWD wells add roughly $44k in expenses per well.

What can we expect from the Lime moving forward?  Companies like Devon and Encana, who’ve recently added 400k and 220k net acres, respectively, will be ramping-up production to delineate and hold their acreage positions.  The core of the play, lying in South-central Kansas and North-central Oklahoma (see map above), has been delineated for the most part and has proven to be consistent.  While the extension area hasn’t been delineated with horizontal production, the area holds more than 7k producing vertical wells and is an oilier field than the core.  SD is beginning to drill wells in the extension area of West-central Kansas (see above maps), where it holds 900k net acres.  The company’s initial extension wells are located in Hodgeman, Finney, Ford, Gray and Ness Counties and the company expects to announce results from these wells later this year.  Apache’s entire acreage position (580k net) lies in the extension portion of the play (see map above), and its delineation will be important to pay attention to.  If SD’s and APA’s wells prove to be as economic as the core, the land grab currently happening in the core will quickly spread North, creating one of the biggest plays in the United States.

1 Based on the following four deals: