Monthly Archives: October 2012

Seeing the Forest through the Debt

Forest Oil (FST) hails from the lineage of noble companies who attempted to increase shareholder value by using financial leverage to increase natural gas reserves during the bull gas market that was 2005 to 2008.  Unfortunately for this lineage, the prolonged period of low natural gas prices that ensued has companies like itself, along with Chesapeake Energy (CHK), Quicksilver Resources (KWK) and GMX Resources (GMXR), et al selling off assets to finance debt like they’re Nicholas Cage.  As an analyst and investor, these are the stories I find exciting because of their potential as a value stock.  I’m not looking for the best run company with the best assets, I’m looking for the best run company with the best assets at the best price.  With that said, screw a sexy company like EOG Resources (EOG), let’s delve into the world that is *cough* Forest Oil.

My research for this piece began with FST’s third quarter 2012 earnings call, which was held on Tuesday October 30, 2012.  I don’t think I’ve listened to a more melancholy earnings call during my admittedly brief analyst career.  Debt aside, at least on paper, I think there’s a lot to be excited about with this story.  The company has 40k net of solid Eagle Ford acreage, 109k net in the Texas Panhandle where it has drilled eight monster Hogshooter wells and an East Texas gas asset that provides its portfolio with plenty of natural gas upside.  I do understand Forest’s attitude, a debt-to-market cap of nearly 200% will keep even the most optimistic financial teams up at night.  So, what are they doing to manage their debt levels?

If you aren’t familiar with Forest’s debt levels, it had total debt of $2.1 billion as of September 30, 2012.  The company is taking a common sense approach to lowering its debt, the first step of which was to refinance half of the six-hundred million it owes in 2014 by issuing lower rate notes which will mature in 2020.  This frees up some near-term liquidity for FST, whose next principal payment isn’t due until 2019 (the company is on the hook for $1.5 billion during 2019 and 2020).  FST will also net approximately $270 million from non-core asset sales which it expects to close on in November and use to lower its debt.  After the refinancing and asset sales, the company will have approximately $1.8 billion in debt outstanding which translates to a debt-to-market cap of 190%.

The remaining $300 million the company will pay in principal in 2014 should be covered through the divestiture of its 114,500 net acres in the Delaware and Midland Basins of West Texas/SE New Mexico.  As shown by the table below, the average acreage value for assets in this area is $4,316 which values FST’s acreage at $494 million.  Even if FST receives a valuation near the lower bound of the sample size, it will still cover its expected principal payments in 2014.  It’s my view that this company should be soluble through the end of fiscal year 2018, but surviving beyond that will require the type of fiscal austerity that would impress even the Greeks.

Recent Permian Transactions

Forest seems to have finally figured out that it doesn’t have daddy’s credit card anymore and needs to start showing some financial constraint.  Its Q4’12 capital budget is approximately $84 million, down 50% from Q3.  For fiscal year 2012, spending will be an estimated $624 million, $59 million less than in 2011.  Next year, spending figures to decrease significantly as the company attempts to spend within cash flow.  It only generated $286 million in cash flow during the nine months ended September 30, 2012 and  if cash flow is flat year-over-year (conservatively speaking), the company will have $381 million to spend next year.  While that’s not the type of spending trajectory we want to see for a potential investment, at least Forest is taking its medicine.

The company’s survival beyond 2018 will be dependent upon its ability to develop its existing asset base while spending within cash-flow.  On paper, it has a great asset in the Eagle Ford with 40k net in Gonzales County, but its results there have been disappointing to date.  Based on the data I saw from the Texas Railroad Commission, the company has one good well in Holmes 1H which has produced more than 100k barrels of oil in just under a year, a handful of economic wells and just as many poor wells.  It’s not unusual for a company to have inconsistent results at the beginning of a drilling program, but I would have liked to see a few more good wells from its Eagle Ford program.  I still think this acreage will turn out to be productive for the company, but FST’s struggles there to date are something to monitor.

The company has had much more success in the mid-continent, where according to its Q3’12 earnings call it has recovered nearly one million barrels of oil equivalent (~70% oil) from eight hogshooter wells during the past year.  This acreage is the company’s prized asset, but it’s going to need its Eagle Ford acreage to be economic for it to survive.

The company’s reserves are currently trading at an EV/Mcfe of $1.46, which is quite a bargain considering its assets.  However, I’m not sold on its ability to develop its existing assets at this point and to be honest I don’t need to be as this company’s stock doesn’t look to be moving up anytime soon.  Also, management seems to be comfortable with maintaining a debt level circa $1.5 billion, which would still put its debt-to-cap North of 150%, a little too high for me.  If you already own the stock, there’s probably no reason to sell as it’s already trading near its bottom.  I’m not touching Forest, but if the debt doesn’t bother you it might be a stock to keep an eye on down the road.


Value Stock Search: Whiting Petroleum

Whiting Petroleum (WLL) is a Bakken focused company with two catalyst plays in the Permian and DJ Basins and an ancillary enhanced oil recovery (EOR) project in West Texas.  While the company has been operating in North Dakota since the 1950s (legacy production is from the Madison formation in Billings County), it burst onto the scene in 2008 with a number of banger wells in Mountrail County.  Its Behr 11-34H well, spudded in April of 2008, has already produced 846k barrels of oil and 495 million cubic feet of natural gas (929 BOE) as of August, 2012.  The Behr well wasn’t alone, as the company seemed to drill gusher after gusher in Mountrail County’s Sanish field through 2010, sending its stock price soaring nearly 250% to $74.50 when it peaked in April of 2011.

Since its peak, lower production rates in the Sanish combined with a lack of (investor) enthusiasm regarding its other acreage plays led to an effective crash in its stock price throughout the latter half of 2011 (see graph below).  WLL’s stock price has since recovered value, but remained 36% lower than its peak when it closed at $48.02 on October 16, 2012.  Was Whiting’s stock overvalued when it peaked?  Maybe.  Is it undervalued now?  That’s the question I hope to sufficiently answer throughout the balance of this article.

Whiting-WTI Stock Price Graph

Source: EIA / Yahoo Finance.

*Adjusted for 2:1 stock split in February, 2011.

Sanish Declines (Total Program)

Source: North Dakota Oil and Gas Commission.

In my analysis of Whiting’s acreage, I looked at 59 wells it had drilled in Mountrail County where the company has 83k net acres and drilled more than 250 wells.  These 59 wells had an average 29-day IP rate of 718 barrels of oil per day (BOPD).  This IP rate projects to an average daily rate during the first year of production of approximately 368 BOPD and a 43% decline in production during the second year.  The decline I calculated was lower than expected and probably lower than Whiting would tell you.  Declines ranged from 22% to 59% in the wells I looked at in this IP rate range (see table above), meaning well size varied and to be conservative we could easily use the upper bound as a decline for this prospect.

(Note regarding methodology: To determine expected production and decline rates, I first looked at a large peer group to determine average production of the entire program and then looked at a smaller, more specified group with rates that I felt would be representative of the entire group average.  From this smaller group (shown in table above), I determined initial production and decline rates.  Economics do not include natural gas sales which vary due to lack of infrastructure in the area.  When calculating payback period, I assumed each well drilled for 328 days in its first year and 344 days in its second year, averages consistent with the wells I looked at.)

Prior to 2011, we could expect WLL’s average Mountrail County well to net approximately $8.4 million (assumes $85 oil and 82% NRI) or 40% more than its average well cost of $6 million, and $5.0 million in its second year assuming a 43% decline or $3.6 million assuming a 59% decline.  These are the robust economics that WLL’s stock price soared under, so what changed?  Well for starters, the company only has about two years left of inventory in Sanish.  Whiting expects to keep nine rigs active in the area, which would imply an upper bound of 216 additional locations assuming each of its rigs drill 12 wells per year which is their maximum rate.

While that’s a lot of Bakken wells, they will only fuel growth for another two years, and adding fuel to the fire, the company’s completions in Sanish have gotten worse over time.  During 2011, the company’s average well produced at a 30-day production rate of 521 BOPD based on the 14 well sample size I looked at, 27% less than the production rate of its entire Sanish program.

Sanish Declines (2011)

Source: North Dakota Oil and Gas Commission.

The table directly above might be a more accurate depiction of the company’s production rates in the Sanish moving forward.  Under this assumption, Whiting would still pay for its well costs in year one with an average revenue of $6.2 million per well (26% lower than average revenue for the total program).  In year two, the well would net an additional $3.7 million assuming a 43% decline or $2.7 million assuming a 59% decline.  While these economics aren’t as robust as the total program economics, the company is still paying for its well costs within a year which is competitive with the operators in its peer group.

Sanish has been Whiting’s most important asset during the last five years.  That’s going to change soon, as the company finishes development of the prospect and ramps-up on its Lewis and Clark/Pronghorn prospect which WLL will speak just as highly of as it does of Sanish.

In Lewis & Clark/Pronghorn, the company holds 261k net acres or 214% more than at Sanish.  I’ve looked at 27 Stark/Billings County wells that Whiting has drilled and the economics appear similar to Whiting’s recent result in the Sanish field, with an average 30-day production rate of 482 BOEPD or 7% less than the rate the company’s Sanish wells produced at during 2011.  While none of the wells in the table below have enough data to determine a one-year decline, I looked at three wells in the prospect that did have enough data, Buckhorn Ranch 31-16H, Froehlich 44-9TFH and Kubas 11-13TFH and extrapolated a 59% decline rate for the entire program.  Average well costs for this program are $7 million per well, from which we can estimate a payback period between one and two years.

Lewis & Clark/Pronghorn Rates (2011)

Source: North Dakota Oil and Gas Commission.

Outside of the Bakken, Whiting has 79k net acres in its Redtail play in Colorado’s DJ Basin.  While WLL has sounded optimistic about its Redtail acreage on conference calls, the reality is it hasn’t had much success in the DJ Basin.  Its well costs, between $4 and $5 million per well, are less than in the Bakken, but its average 30-day production rate is only 229 BOEPD (82% oil) per well.  Whiting is still tweaking its drilling and completion techniques here, but both Noble (NBL) and Carrizo (CRZO) have had more consistent rates in this field.  The Niobrara is a difficult formation to operate in, just ask Chesapeake (CHK) and GMX Resources (GMXR), who have both put their acreage up for sale.  WLL might be better off doing the same or entering into a JV with an experienced Niobrara operator.

Whiting’s Big Tex prospect in the Permian Basin could be a catalyst for the company as it has 87k net acres in the play.  Its results here have been stronger than in the Niobrara, meaning it might have a new play from which it can increase its reserve life and provide cash flow for the development of its Bakken acreage.  The company’s EOR project in Texas is another nice cash flow piece for the company, but it’s not going to provide much of a stock price catalyst moving forward.

Whiting Valuation Table

On an EV/Production and EV/Reserves basis, Whiting is undervalued with respect to its peer group by a long-shot.  The market is valuing its production and reserves by approximately 60% and 40% less than the peer group average, respectively.  The market is not only questioning the quality of its reserves, but also the quantity as the table shows its reserve life is much lower than the peer group, which indirectly effects its production valuation.  To give you an idea of how undervalued Whiting is, its production rivals Continental’s (CLR), while its enterprise value is 43% of CLR’s.  Is the market correct in its assessment or has Whiting’s stock been oversold?

Whiting has one major hole in its story and that’s reserve growth.  I believe the market is undervaluing its Lewis & Clark/Pronghorn assets which should provide stable growth for the company moving forward.  With its Starbuck, Missouri Breaks and Big Island prospects, it has several other acreage positions in the Bakken which could serve as catalysts for the company down the road.  I view its prospects in Colorado and Texas as ancillary to its Bakken acreage, but nothing to get too excited about.  Additionally, it’s a company who has been mentioned in M&A talks recently and it could provide oil weighted production for a gassy major or an Asian company looking to bring oil back East.  The bottom line is these guys are an experienced operator that produces a lot of oil from one of the better basins on the planet.  Whiting might not make you rich, but it’s cheap right now, which makes it an attractive buy despite its deficiencies.

The Well Map

While I’ve been working on a new write-up for this site, I’ve been busy developing “The Well Map” which is a project I will be working on for a long-time.  I’m mapping (mostly) unconventional wells in the United States, with my current focus on the Rocky Mountain region.  If you visit the site, click on a well location to view the operator, location and initial production (IP) rates.  This project is in its infancy, but check it out periodically as I will be updating it on a regular basis.


The Energy Harbinger

Peaking in at Hess’ Production Results in the Bakken

I’m currently working on a Bakken operator efficiency article, but I’m not sure how long it’s going to take me and I’d like to keep this blog updated at least twice a week, so I thought I’d prepare a preview of sorts based on some of the research I’ve been doing.  This preview will focus on Hess’ (Hes) results in the Bakken where it has been using 16 rigs to develop its 800k net acres. Like any company with an acreage position this big, some of it’s good and some of it’s marginal.  The company is currently drilling to hold acreage so its production results have been inconsistent.

Why Hess? Well they’ve been producing in North Dakota since 1951, making them not only one of the state’s oldest producers but also one of its top producers with respect to volume.  To that end, it’s interesting to hear people who participate in wells with Hess speak of high AFEs and modest production volumes.  On paper, I would expect more from a company who has been drilling in the Bakken as long as Hess.

The company’s reason for lackluster production stems from its decision to hold all of its acreage, even the fringe pieces.  Production from the fringe pieces isn’t as good, resulting in weaker than expected production numbers.  In its Q4’11 earnings call, the company explained its higher AFEs are also a result of its HBP drilling program.  The company is preparing its drilling units for pad drilling, so the initial wells are bearing all of the infrastructure costs for the pad.  While this implies lower costs for wells down the road, it hurts the non-operators who are participating in its earlier wells.

A few notes on terminology: 1) An AFE is an “authorization for expenditure,” which is the bill an operator sends out to the non-operators/investors in a given well.  2) HBP=held-by-production.  Basically, Hess has to drill all of its leases before the initial term of approximately five years expires or they will revert back to the landowner and have to be leased again.

Below is production results and maps of the company’s various drilling areas in the Bakken. For those of you who aren’t familiar with North Dakota’s geography, below is a map of North Dakota by County which will provide you with perspective when looking at the maps further below.  The Bakken is found in the Western half of the state with the majority of production emanating from Williams, Mountrail, McKenzie and Dunn Counties.

Williams County Data source: North Dakota oil and Gas Commission.

The map above shows eight wells drilled in Williams County by Hess from 2010 to 2012.  The orange circles on the map indicate a township and the “pin” shows the section of the township where the well is located.  The wells are identified by name and IP rate (IP days varied due to limited data).  Hess’ best wells were in the Southeast portion of the county and production declined as the company moved Northwest.  The table below shows that Williams County is probably the gassiest Bakken County, with Hess’ wells averaging 80% oil.

Data source: North Dakota oil and Gas Commission.

Hess’ Williams County wells averaged 692 barrels of oil per day during the first 45 days of production.  This type of well performance implies a recovery of 77,887 barrels of oil during the first 239 days of production which will gross $6.6 million at $85.00 oil (if Hess sold all of its gas, which it didn’t, we could add on another half million).  Assuming the well grosses another 14,000 barrels during the balance of this year, it should have a payback period between two and three years assuming $10 million well cost and 80% NRI. The problem with Hess is some of these early Bakken wells are much more expensive (I’ve heard of some in the $17 million range), meaning you aren’t getting your money back anytime soon.

Mountrail County Data source: North Dakota oil and Gas Commission.

Hess’ acreage in Mountrail County seems to be solid, with the exception of the Shuhart well to the Northeast in 156-90.  That well is just North of some of the biggest wells in the Bakken, but it’s in an area where production begins to get a little spotty.  Also, the table below shows the company’s well performance is trending upwards, with its recent Johnson and Fretheim wells both having 30-Day IPs in the 1,000 barrels of oil equivalent per day (BOEPD) range.

Data source: North Dakota oil and Gas Commission.

While these numbers show Hess’ Mountrail County wells to be the company’s worst performer, its production in the county is trending up and the Shuhart well brings average production down.  The company has drilled a lot more wells in these counties to date (compared to the sample size), and it wasn’t my aim to show its worst performers, but the performance of the areas the company had leasehold in.  It should be noted that moving forward, the company will be drilling its best areas which will improve its production statistics.  The obvious takeaway here is that not all of the company’s 800k acre position is going to be economic.

McKenzie/Dunn County   Data source: North Dakota oil and Gas Commission.

While I didn’t look at every single Hess well to date, I can tell you the vast majority were in Williams and Mountrail Counties, meaning most of its acreage is probably in those two counties.  That’s unfortunate because the company’s best wells in my analysis (HA-Mogen and Arnegard State) were in McKenzie County.

Data source: North Dakota oil and Gas Commission.

As shown above, McKenzie and Dunn Counties (mainly McKenzie) are where the company has drilled its most economic wells to date.  Assuming $85 oil and an 80% NRI, payback period on these wells will average between one and two years.

Conclusion: Hess’ Bakken acreage lies in Williams, Mountrail, McKenzie and Dunn counties and tends to be in productive areas.  Where the company is getting itself into problems is with the high well cost of some of its wells.  Hess has apparently gotten this message, as it stated in its Q2’12 earnings call that it’s switching from a 38-stage hybrid frack (these wells averaged $13.4 million a pop during Q1’12) to a 34-stage sliding sleeve for its infill drilling or for all wells completed after the company’s acreage is HBP.

As for its decision to pile infrastructure costs onto the first well drilled on a pad, I don’t understand this decision and it would be interesting to know if other operators follow the same practice.  I’m not all that familiar with how pad drilling works and I’m a little skeptical of the company’s higher well costs.  Are we to believe that they’re really the result of infrastructure build out, or is there something more going on with the company’s Bakken efficiency?  I hope to answer this question with my full report which should be available next week.

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.