Tag Archives: Bakken

The Well Map Update (12-3-13)

Testing is finished with The Well Map and we’re going to go live next week. Here’s what you need to know:

*There’s roughly 13k wells on the map and we’ll be adding more each week.
*The 13k wells include areas such as the Bakken, Eagle Ford, Miss Lime, Powder River Basin, DJ Basin, Piceance Basin, Permian Basin, Granite Wash, Marcelllus and Utica.
*We’ll be updating existing data and adding new data all the time. Wells from the San Juan Basin, SCOOP and Marmaton are coming soon.
*For quick analysis of the data we’ve installed several filters including operator, well name, formation, wellbore, spud date, state/county and production ranges.
*Once data is filtered, the filter summary averages the data filtered which allows the user to pull data points such as average production by operator, formation or state quickly.
*The map will be free, all you have to do is sign-up.
*If you want to stay up to date on the new wells we add each week and crunch raw data, we’ll be offering several newsletters containing just that, these start at $50/month.
*To stay up to date on new features and launch information, like us on Facebook and follow us on Twitter.

Thanks for your support,

The Well Map Team

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EOG Bakken Production Summary

Below is a graph of EOG Resources’ production results from North Dakota’s Bakken Shale by County.  The graph contains data on 414 Bakken wells drilled between 2008 and 2012, with 29 in McKenzie, 4 in Dunn, 344 in Mountrail, 26 in Williams and 11 in Burke.  Based on the data I collected, EOG’s average 30-day IP rate in the Bakken is 619 barrels of oil per day (BOPD) and 310 thousand cubic feet of natural gas per day (Mcfpd) or 671 barrels of oil equivalent per day (BOEPD) with an oil cut of 92%.

EOG’s Bakken Results by County
EOG_Bakken-results-by-county
Source: North Dakota Oil & Gas Division / The Energy Harbinger.

Most people think of EOG as a Parshall Field (Mountrail County) company and that’s certainly its core acreage; however, it has achieved solid results in both McKenzie and Dunn Counties.  I have data on 33 wells in McKenzie and Dunn, and these wells should all be considered part of the same play despite encompassing two separate counties as they lie where the Southeastern corner of McKenzie and Northwestern corner of Dunn County meet.  I’m not sure how much acreage the company has in this area, but the results have been strong to date.

EOG’s Mountrail County wells are the cornerstone of the company as it has drilled 344 wells there with an average 30-day IP rate of 632 BOPD.  Approximately 60 or 17% of the total wells it has drilled in the County have achieved 30-day production rates of more than 1,000 BOPD.  These results have helped put EOG in the upper echelon of independent oil and gas companies and contributed to its stock price more than doubling to $121.55 as of market close December 26, 2012 from $58.47 on market close January 3, 2007.

It doesn’t hurt that the company is also well positioned in the Eagle Ford where it has 644k net acres prospective for 65-90 acre spacing units or more than 8,000 well locations.  While it’s unlikely all of these well locations will be drilled, the inventory is impressive to say the least.

EOG is also building a position in the Tuscaloosa Marine Shale (TMS), where it recently completed its first well in Avoyelles Parish in 23 days, much faster than other TMS operators.  This is an important result, because production results have been strong in the play but costs have been high.

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I hope to do more posts like this moving forward so you guys can see more in-depth production data for companies you’ve invested in or are interested in.  As always, ask questions if any of the data/analysis seems odd.

-TEH

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.

Putting Kodiak’s Valuation into Perspective

If you’ve bought Kodiak’s (KOG) stock in 2012, there’s no doubt you’ve paid a premium.  Outside of a few earlier stage companies, there’s not many independent U.S. E&P companies that trade on multiples as high as Kodiak.  This doesn’t necessarily mean you overpaid or that the company is overvalued, because with reserve and production growth of more than 500% and 400%, respectively, it has been growing faster than Barry Bonds’ nose during the past year (year and half for reserves).

Just how highly valued is Kodiak?

Well, the company is trading at an enterprise value to trailing-twelve months production (EV/TTM Production) of $1,027 per BOE ($374,773 per flowing barrel) and EV to reserves of $46.05 per proven reserve.  These multiples represent a 105% and 33% premium, respectively, to the peer averages in the chart below.

For KOG to receive a valuation on its production equivalent to that of the peer group below, it would need to produce at a TTM Production rate of 6,452 thousand barrels of oil equivalent (MBOE) or 17.7 MBOEPD, which is 105% more than the company’s TTM production at June 30, 2012.  While this number is significantly more than the company’s TTM number, it’s not much more than the company’s current production rate.  In its second quarter (Q2’12) conference call, KOG revealed that it produced at a rate of 17,000 BOEPD during July and if the company keeps this rate flat for the next year its TTM production will be 6,205 BOEPD, nearly the same rate as the peer group multiple implies.  Furthermore, the company expects to exit 2012 producing at a rate of 27,000 BOEPD, so one could easily argue that KOG’s current production will outgrow the peer group production multiple below within the next year.

Kodiak Peer Multiples

The peer group reserve multiple above of $34.59 per BOE implies that the market expects KOG’s reserves to be valued 33% higher than the peer group, meaning the market believes KOG is turning unproven reserves to proven reserves at a relatively higher rate.  There’s plenty of reason to agree with the market’s assessment, as KOG has grown reserves more than 500% during the past two years and more than 36% so far this year.  While growth as a percentage may slow down moving forward, the fact is the company has only completed 82 of its 807 net potential well locations in the Bakken, meaning it has plenty of acreage to prove up and grow reserves.

Of these 807 potential locations, 564 of them lie in the company’s Dunn County, Koala, Smokey and Polar prospects where its completions have been strong.  Where the company may run into trouble with its margins in the Bakken are with its Grizzly and Wildrose prospects, which comprise 244 or 30% of its net locations.  The Grizzly prospect wells have been smaller to date and the company attributes this to lower pressure in the Western portion of the North Dakota Bakken.  Its most recent completions in the prospect have had 30-day IP rates of 328, 248 and 394 BOEPD which is approximately 1/3 of the rates it has achieved in its Koala prospect.  KOG does anticipate these wells having shallower declines, but it remains to be seen how economic they will be.

The company has shelved drilling in its Wildrose prospect (this acreage is HBP) for the balance of 2012 after completing two wells there.  It does expect to earn 20% IRRs across this acreage, but believes the economics there are not as strong as in its other acreage.  While this bodes well for economics in its other acreage, the Wildrose wells came in below expectations (one came in at 225 BOEPD) and this combined with the company’s plans to shelve the acreage for now doesn’t speak highly of it.

Kodiak’s Metrics

Financially, Kodiak is in decent shape with respect to its peers.  Average LOE and G&A costs per BOE without HK (HK was included in this analysis for its valuation multiples) total $14.03 and $7.58, respectively, meaning KOG could improve its valuation by operating more efficiently.  The company should pare down expenses as it matures as an operator and increases scalability.  CLR does bring down the costs in this analysis, but note it’s a more mature company that is very well run.  I’m comfortable with KOG’s current debt level; however it’s getting close to debt levels that the market could deem excessive at its current size.  The company’s interest coverage ratio is low, particularly with respect to its Bakken peers (CLR and OAS).  While it only recorded interest expense of $8.2 million during the six-months ended June 30, 2011, it actually paid an additional $25.0 million in interest expense, but this amount was capitalized.

KOG was been a serial issuer of equity capital during the past few years and has begun to issue debt as of late.  While the company has succeeded in putting this capital to work, its financial condition will be in a lot better shape once it grows production to the point where it can spend within cash flows.  Operating cash flows for the first six-months were only $90 million and while this figure will improve substantially during the balance of the year, the company will have spent an estimated $650 million on capital expenditures by the end of 2012 and I doubt it slows down spending anytime soon.  I’m not raising the red flag on KOG, but there’s certainly a chance it goes to market to fund its 2013 capital expenditures and its debt levels (while manageable at this point) deserve monitoring moving forward, particularly if oil prices take a dive.

There’s a lot of reasons to like Kodiak.  It has a strong asset base with more than 100k premium Bakken acres giving it plenty of room for future growth.  In addition, these guys are great operators who run an efficient company which will only become more efficient as it grows.  Where it runs into trouble is that it’s trying to grow faster than its balance sheet can handle and its liquidity issues will start to compound if it continues to sell debt.  KOG is constantly mentioned in acquisition talks these days, and for good reason as I believe it needs someone to take it to the next level.  To that point, it’s worth noting that Brigham was bought by Statoil (STO) in 2011 at a 36% premium while GeoResources (who did own some Eagle Ford) was bought by Halcon (HK) last spring at a 24% premium (I’d expect something closer to Brigham’s premium for KOG).  If management chooses not to sell, investors should be prepared to be diluted again sometime within the next six-months.  I would buy this stock at its current valuations, but I wouldn’t pay much more.

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.