In the last post I demonstrated that 12.885 million out of 19.367 million barrels of oil equivalent (BOE) in "proved reserves" was being sold by Gulfport to a related party of Wexford. These were the Permian Basin fields as per the table below.
| Proved Reserves | ||||||||||||||||||||||||||||||||||||||||
Field
| NRI/WI (1) | Productive Wells (2) | Non-Productive Wells | Developed Acreage (3) | Gas | Oil | Total | |||||||||||||||||||||||||||||||||
| Percentages | Gross | Net | Gross | Net | Gross | Net | MBOE | MBOE | MBOE | |||||||||||||||||||||||||||||||
West Cote Blanche Bay Field (4)
| 80.108/100 | 95 | 95 | 189 | 189 | 5,668 | 5,668 | 352 | 3,617 | 3,969 | ||||||||||||||||||||||||||||||
E. Hackberry Field (5)
| 79.424/100 | 30 | 30 | 93 | 93 | 3,291 | 3,291 | 226 | 1,606 | 1,832 | ||||||||||||||||||||||||||||||
W. Hackberry Field
| 87.5/100 | 2 | 2 | 23 | 23 | 592 | 592 | — | 76 | 76 | ||||||||||||||||||||||||||||||
Permian Basin
| 35.4/46.87 | 121 | 57 | — | — | 8,880 | 4,119 | 2,008 | 10,877 | 12,885 | ||||||||||||||||||||||||||||||
Niobrara Formation
| 39.7/47.9 | 6 | 3 | 2 | 1 | 3,954 | 1,977 | 26 | 500 | 526 | ||||||||||||||||||||||||||||||
Williston Basin (6)
| 2.8/3.3 | 6 | .2 | — | — | 1,708 | 132 | 7 | 67 | 74 | ||||||||||||||||||||||||||||||
Overrides/Royalty Non-operated
| Various | 133 | .2 | — | — | — | — | 3 | 2 | 5 | ||||||||||||||||||||||||||||||
Total
| 393 | 187.4 | 307 | 306 | 24,093 | 15,779 | 2,622 | 16,745 | 19,367 | |||||||||||||||||||||||||||||||
The table is from the 10K.
Given that most the reserves and most the cash flows of Gulfport are being sold to a related party it is worth considering the quality of the assets left. After all - if you are a Gulfport shareholder that is what you are buying.
Lets just take the Niobrara acreage.
The claim of half a million barrels of oil in the Niobrara raised my eyebrows because I thought most that acreage was locked up. Indeed it was this claim that attracted me (as a short) to Gulfport in the first place. I wanted to see what they based their claim of half a million barrels of proved oil on.
Here is what the 10K says about the Niobrara acreage:
Location and Land
Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in northwestern Colorado, and held leases for 14,993 acres as of December 31, 2011. We are the operator on the acreage.
Area History
The Niobrara Formation is a shale oil rock formation located in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara formation has emerged as another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara has a history of producing through conventional technology with some of the earliest production dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and limited in area extent. We believe the Niobrara can be produced on a more widespread basis using today’s horizontal multi-stage fracture stimulation technology where the Niobrara is thermally mature.
Geology
The Niobrara Formation oil play in northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect oil generation. The producing intervals are geologically equivalent to the Niobrara reservoirs of the DJ and Powder River Basins which are currently emerging as a major crude resource play.
Production Status
In the fourth quarter of 2011, our net production from our Niobrara acreage was 3,390 BOE, or an average of 37 BOE per day, 100% of which was from oil. From January 1, 2012 through January 31, 2012, our average daily net production from our Niobrara acreage was 41 BOE, 100% of which was from oil.
Facilities
There are typical land oil and gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units.
Recent and Future Activity
We drilled three gross (1.5 net) wells at Niobrara during 2011. We have completed a 60 square mile 3-D seismic survey over our Craig Dome prospect, have received a processed version of the seismic and are selecting future drilling locations. We currently intend to drill five to seven gross wells at Niobrara during 2012.Production - net - was 37 barrels of oil per day during the fourth quarter of 2011. In January they raised this to 41 barrels of oil per day.
The most recent 10Q filing contains this text.
Niobrara Formation. Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara formation in Colorado and held leases for approximately 14,993 acres as of March 31, 2012. Aggregate net production from the Niobrara play during the three months ended March 31, 2012 was approximately 2,638 BOE, or 29 BOE per day. During April 2012, average daily net production in Niobrara was approximately 66 BOE due to completion of our 2011 drilling activity.So for the first quarter the production fell to average only 29 BOE per day after averaging 41 BOE per day in January.
41 BOE per day in January implies production of 1271 barrels (approx) in January (being 41 BOE per day times 31 days).
We are told that production in the quarter was 2638 barrels. Simple arithmetic implies that production in February and March was 1367 BOE. Assuming 60 days in those months (29 in February, 31 in March) we get production of 22.8 barrels per day. A fairly sharp drop from 41 BOE per day in January. This may be a decline rate or it may be weather or other shut-in (we do not know). However shut-ins are more likely in January so decline is a reasonable guess.
After completing drilling activity for 2011 the production rose to 66 BOE per day.
These are not big numbers and production drops seem large. Indeed flow rates almost halved within the first quarter.
However the company states that 500 thousand barrels of oil in reserves are proven in this field.
It is a cliché that you only know what the reserves of an oil field were when the last barrel is produced. There are many fields that have surprised to the downside and some that have surprised to the upside.
I will leave it to my readers to judge - whether on the basis of the relatively small production and high decline rates demonstrated - they regard the 500 thousand barrels of proved reserves listed here as a solid number.
John
10 comments:
Can you ask IR point blank about the discrepancy between the production rate and the claimed reserves? How do they explain it?
This is well spotted John.
I'd suggest that several companies (with a keen eye toward australian gas producers) with 'unconventional/tight' hydrocarbon production exhibit similar issues.
Based on the flow rates, much of this reserve will need further development to be produced. However it is extremely unlikely that, such development is value adding, reserves definitions require that development be profitable for classification of resources as reserves, however profitable is vague, and cash flow positive over 50 years would probably qualify.
Either way, its worth a maximum of 0, and usually less
This is extremely detailed Mr. Hempton. And when presented one piece at a time, the temptation to play devil's advocate is almost irresistible. Its like a game of twister.
Anyway I think much of this -- not all but most -- could be explained by saying that you are painting a picture of an exploration company. If GPOR's business is exploration, not extraction, then proven reserves are the product. They are divested, and possible/probable reserves are not reported in SEC filings. In that light, low production numbers, the capital-intensive nature of the business, the low employee count, heavy contracting, and some of the deals would all kind of fit together.
On the other hand, all of the weird perverse incentives and questionable dealings going on with the Wexford-controlled circus seem like your strongest points. What I think would bolster your case significantly would be an example of a squeaky-clean exploration company (the "Givaudan" of hydrocarbon exploration), while Hempton-quality takedowns of other similar companies might weaken it considerably ("this is just how this business works").
Now I will hold my breath in anticipation of an uber-damning Part V.
Anadarko is drilling in the Niobrara and is reporting as much as 600 MBOE of Estimated Ultimate Recovery (EUR or "Reserves") per well. Gulfport booking 500 MBOE of proven reserves for three net wells plus one non-productive one doesn't sound like a lot at all.
I'm a big fan of this blog, but so far this sounds like another NOG - you've uncovered a lot of smoke and some shady related party transactions, but no outright fraud.
Both NOG and GPOR have fallen because Wall Street is grown disenchanted with E&Ps for a variety of reasons (natural gas prices circling the toilet, midcontinent oil basis differentials widening, operational setbacks).
I think this is missing the point Anon. Whether they are an explorer or not, the flow rates are suggesting that the reserves are suspect.
But the 500K is a minor fraction of the claimed reserves so even if it turns out to be zero, it only amounts to 2 0r 3% of reserves. (Although if they are falsifying that, there will be more cockroaches crawling out of other wells.)
(This is anon 9:49 Re: flow rates)
I think it would help to try to imagine how this could happen. I am not an expert and have no special knowledge of this company, all I have is a theory that happens to fit the facts (as Spock would say). So consider the following (call it alternative scenario A):
Alternative Scenario A:
GPOR has a tanker truck. It has a capacity of slightly more than 200 barrels. For maintenance reasons, every Tuesday they run their pumps to get a bit of flow: enough to about fill the tanker. They do not run their pumps full blast because oil is not the product, proven reserves are the product.
Coincidentally, this means they took 5 truckloads in January. Also, in February, the truck driver took a week off and went to mardis gras, so they skipped a week.
This concludes Alternative Scenario A.
It is possible that GPOR has some of the least productive acreage versus the other Niobrara operators.
Why? Because GPOR's own 10Q states that their acreage is in "northwestern Colorado".
Unfortunately for GPOR, the Niobrara is a formation in northeastern Colorado.
Of course, management could just be morons who don't know where their acreage actually lies.
I thought about the tanker-truck hypothesis - but the 10K says this:
Quote
There are typical land oil and gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units.
Endquote
I guess it is possible - but there is gas processing and separation (even though they did not produce gas). I honestly do not know.
John
Export constraints are (From what I have been reading) a potential explanation.
Im aware of at least 1 development in North Dakota where development has been delayed due to infrastructure capacity issues. ie there is simply too much production for the existing pipelines to handle
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