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Boy, was that a bad third quarter conference call or what? ATP Oil & Gas (ATPG $8.50) has disappointed investors once again with lower than anticipated production in the third qarter and reduced investor expectations for the fourth quarter.

As recently as Sept, management was discussing production of 31 mboe/d, including the new 3rd well at their Titan platform pre-production testing at 7. However, due to production management issues, the well is currently producing at a 3.5 rate. By possibly ramping up production too fast, or the realization that the sand in the reservoir is finer than first anticipated, sand has migrated into the well bore, restricting product flow. The cure is either a shut-in and re-work or a sidetrack to another entry point into the reservoir. In addition, the Mississippi Canyon A-1 well is now an on- and off-line schedule, with shut-ins used to build up pressure, further reducing production.

Production for the quarter was also negatively impacted by a Tropical Storm shut-in, a routine temporary shut-in of the Titan platform as work on the fourth Titan well progresses, and compressor issues at Gomez. Production for the quarter was 24.2, or 20% below the 29 average that was expected.

Management forecasts production in the 4th qtr to be in the 23 to 26 mboe/d, with current production between 24 and 25. This will create a relatively flat production rate for the year with each quarter being between 21 and 24 mboe/d. Production is slated for 24 mboe/d from Gull deepwater and 1 to 2 from the North Sea.

Management also gave several new timetables and updates on various projects:

  • Clipper will begin to construct the pipeline laying procedure for eventual tie up with the Murphy Oil’s Frontrunner production platform in late July;
  • Gomez wells #8 and #9 will most likely be “flipped” to begin drilling activity in November;
  • Titan #4 well completion and on-line production will be delayed until Jan-Feb due to finding higher pay zones. Although the production is a few months delayed, the added reserves will prolong the life of the production footprint;
  • Actual production from the Titan #4 well has not yet been determined, but management is planning on 7+, with full well production sometime mid-2012, as they bring production up at a slower pace than the previous Titan well;
  • Octobouy is still on track for deployment next year with the first of 16 (14 producers, 2 injection wells) North Sea wells to begin drilling in late 2012;
  • There was no update on the schedule for the Easter Mediterranean prospects;
  • Based on anticipated larger year-end reserve calculation from both quantity and pricing, their credit line may be redetermined by about $50 million higher;
  • Realized prices climbed from $79 to over $100 a barrel of oil equivalent.

Using these new timetables and with Gomez #8, #9 wells along with the North Sea expansion becoming 2013 events, it seems average quarterly production could look like this:

  • 3rd qtr 2011: 24.2 mboe/d
  • 4th qtr 2011: 25.0
  • 1st qtr 1012: 31.0 (Titan #4 on line at 7 by mid-Feb, Atwater rework of 1.5 and A-1 of 1.5)
  • 2nd qtr 2012: 35.0
  • 3rd qtr 2012: 35.0
  • 4th qtr 2012: 47.0 (Clipper on-line at 12, equaling the fix-price portion of the negotiated contract with Frontrunner)
  • Average 2012: 37.0

At an average of 37mboe/d for 2012 production, operating cash flow (ocf) could be in the $9.00 to $10.00 per share range, or about $450 million to $500 million. At current production levels of 25, ocf is about $3.50/shr, or $180 million, annualized.

Management also gave a hint of 2012 capital expenditures in the $500 million range again. Of this, management is planning on $150 million to $160 million from rollovers of NPIs and ORRIs. With NPI payoffs in 2012 of between $220 million and $250 million and up from $180 million this year, an average of 37 mboe/d could generate a reduction of NPIs in the $60 million to $100 million range. Internally funded cash flow or capital generated from other sources will compose the balance.

When discussing the Clipper prospects, the potential was raised of bringing in a joint venture partner for the pipeline, the producing field, or both. The pipeline construction cap ex is expected to be around $100 million. This additional capital could be used to fund overall 2012 cap ex, and no decision will be made on this until 1st qtr 2012. It is possible a deal could be structured similar to GE’s investment in the Innovator assets.

Where does this leave investors? The simple answer is: wanting more. More clarity and transparency on production is essential to create forecast creditability. As recently as six weeks ago, production was forecast to be 20% higher, there would be no need for additional NPIs and 2012 cap ex would be within ocf constraints. Clearly, that is not the case and at some point over the past six weeks, management should have fessed up to their production problems and schedule changes.

Investors want higher production and the ocf that comes with it. The product is in the ground as shown by reserves, but investors need the cash flow it represents in the bank. Within the difficulties of deepwater oil drilling and production, investors are still waiting for their payoff.

It is obvious management was taken by surprise by these events. Since mid-year, insider buying has been well documented at prices that are now substantially higher, and it would be excessive to accuse management of purchasing over $2.5 million of shares in the open market if they knew share prices would collapse by 50%. However, their history of over-promising and under-delivering continues unabated.

As management and investors know, ongoing production levels of 25 mboe/d is insufficient to continue their over-leveraged debt service and ambitious cap ex program.

2012 was previously billed as a game changing year. Now, it appears to be another year of muddling along, struggling to reach the 40 mboe/d required to internally fund cap ex and NPI payments. With this revelation, share prices are being hammered – again. The shorts have no real sense of urgency to cover and long investors have seen their short-term production targets evaporate. Not a pretty picture nor a set-up for substantially higher equity prices soon.

While not in danger of defaulting on its debt, the current and anticipated production indicates, as seems to be historically the case, a longer timeframe for ATP to realize its potential. With tax loss selling season drawing closer and inadequate production growth catalysts in the short term, ATPG continues to be a “tomorrow” story.

The bottom line is, like so many other promising oil and gas outfits, the prospects are there, the market pricing is there, and the oil reserves are there. However, if this management team is unable to execute, there are others that can, and maybe will.

As always, investors should conduct their own due diligence, should develop their own understanding of these potential opportunities, and should determine how it may fit their current financial situation.

Source: ATP Oil & Gas: Still A 'Tomorrow' Story