August 28, 2009
MEMORANDUM
TO: | Mr. Roger Schwall Mr. Jim Murphy Mr. Sean Donahue Mr. Karl Hiller Ms. Jennifer Gallagher Division of Corporation Finance Securities and Exchange Commission | |
FROM: | Carrizo Oil & Gas, Inc. | |
RE: | Carrizo Oil & Gas, Inc. Form 10-K for the Fiscal Year Ended December 31, 2008 (File No. 0-29187-87) and Form S-3 (File No. 333-159237) Response to SEC Staff Comments Received by Telephone on August 20, 2009 |
We thank you for taking the time to speak with us by telephone conference on August 20, 2009, and we are responding to comments received from Mr. Roger Schwall during that conference call in the order in which he raised them. For your convenience, our responses are prefaced by Mr. Schwall’s corresponding comment in italicized text as we wrote them down during our conversation. These comments are not a transcript but our understanding of what he was requesting from us.
We respectfully request that the Staff review our responses to its comments at its earliest convenience. This process has continued for some time and we desire to resolve these comments as quickly as reasonably possible. Please advise us of any further comments at your earliest convenience.
1. | Please explain when and why the decision was made to terminate the effort to use cogeneration in the Camp Hill field and how and why the Company transitioned to steam flooding in the field. | |
As recalled during our conference call, this question was a central topic of your review of our Annual Report on Form 10-K for the year ended December 31, 2004 in 2005-06. As explained in our letter to the Staff dated December 13, 2005, perhaps the most important reason for the delay in the development of our Camp Hill properties up to that time was the potential for drastically improved profitability that would result from the construction of a nearby cogeneration plant. Cogeneration plants typically provide steam at less than half the cost of small steam generators. Although the steam drive process is efficient at maximizing oil recovery, the cost of steam generation is one of the key issues to address in the design of the steam drive process because natural gas or produced crude is burned to create the steam injectant. Steam costs far outweigh capital costs. |
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Our management has had experience with cogeneration plants and their impact on steam drive fields in the Belridge, Midway Sunset and Kern River fields in California and initially believed that the demand for electricity in the East Texas area would increase in the future such that it would become lucrative for us or a third party to build a cogeneration plant in the area. In this cogeneration plant, a gas turbine would be used to generate electricity, and the waste heat would be used to produce steam, which would be captured for injection in the Camp Hill field. We negotiated for some time with a party regarding the building of a cogeneration facility. In 2000, we received a bid from that cogeneration provider to provide steam at 75% of our usual steam generation cost. We did not accept this bid because we believed, based on our experience with cogeneration plants, that more favorable terms were achievable. We subsequently worked with industry consultants to explore the possibility of a cogeneration facility in the Camp Hill field. | ||
In mid-2005, we reengaged an electricity industry consultant with cogeneration experience, to further investigate the feasibility of establishing a cogeneration plant in the area. After extensive discussions with the consultant, we concluded that there continued to be overcapacity of electricity in the regional market and that overcapacity was not likely to reverse itself in the near term. This condition in the power markets, combined with the relative inefficiency of the expected small cogeneration plant that would supply the steam, dictated that the capital expenditures associated with building a cogeneration plant were not likely to be warranted for a period of several years. Following the receipt of our electricity consultant’s input regarding the economics of establishing a cogeneration plant, we determined that, rather than awaiting any change in the electricity market that would make the construction of a cogeneration plant more lucrative, we would further develop our Camp Hill properties with steam generators. During the time that we delayed full scale development of our Camp Hill properties as we explored cogeneration, we nevertheless continued to improve the ultimate efficiency of our development plan by negotiating and acquiring certain surrounding leased acreage, as well as the purchase of surface acreage that would be impacted by the field development. We were able to increase our ownership interests on more favorable terms by deferring full scale development, thereby further improving the economics of development and favorably affecting the development plan for the steam drive patterns. | ||
As discussed in our recent comment response letters, we have greatly expanded and accelerated our development activities in the Camp Hill field since abandoning our plans for a cogeneration facility in 2005. | ||
2. | Please explain why the Company’s reserves in the Camp Hill field were not revised when the Company terminated the effort to use cogeneration and began using steam flooding in the field. | |
As recalled during our conference call, following the Staff’s 2005-06 review, we believed that our reserves in the Camp Hill field did not need to be revised as a result of management’s decision to use stand alone steam generators, instead of cogeneration, to develop our properties in the field. Our reserve report for the Camp Hill field has never assumed the use of cogeneration but always used the more conservative (and as explained |
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above, more costly) approach of assuming the use of stand alone steam generators; the move away from the cogeneration strategy did not therefore require a change to the reserve report. Additionally, there was no other independent reason to revise the reserves as a result of this decision. Throughout the period we have owned properties in the Camp Hill field, we have always planned to develop the reserves and it has always been economic to do so, whether by means of cogeneration or by traditional steam generators. We did delay development activities in an effort to make a profitable (steam generator driven) project even more profitable through cogeneration. However, both before and after our change in strategy and while steam injection was suspended, the reserves remained in place as proved undeveloped reserves because (1) we had been and remained ready to make the capital expenditures or facility expansions that were required to recommence steam injection, (2) we and our third-party engineer remained reasonably certain as to the production of these reserves and (3) we had the intent to develop fully the field. Although not tied to the change in strategy from cogeneration to steam generators, as part of the 2005-06 review, we did lower the estimated recovery efficiency after steam drive for the entire Camp Hill field and remove several specific patterns from the proved undeveloped reserves classification. |
3. | Please explain why it is appropriate to classify the reserves in the Camp Hill field as proved undeveloped, as shown in the Company’sForm 10-K, given that it may take approximately 15 years to fully develop all of the reserves. | |
For reasons explained in our letters to the Staff dated June 15, 2009 and July 9, 2009 and letters submitted during the Staff’s 2005-06 review, our proved undeveloped reserves in the Camp Hill field meet the current definition of proved undeveloped oil and gas reserves. As we noted during our conference call, we strongly believe there is no doubt that the reserves can be developed economically under both current and future reasonably anticipatable costs and prices. | ||
However, during our conference call, the Staff explained that its concern was with the time-frame of the development of our reserves in the field. In particular, the Staff seemed to place great emphasis on the belief that undeveloped reserves should generally be developed within five years if they are to be classified as proved. Further, the Staff expressed the view that, even though development operations in the Camp Hill field, including drilling and installation of steam injection equipment, would continue for a projected 15 years through 2024, our classification of these undeveloped reserves as proved was extremely unusual if not unprecedented. For the reason set forth below, we respectfully disagree with this view. | ||
We have consistently informed the Staff and investors of our plans. |
In our public filings, we have consistently been both detailed and up-front with both the Staff and our investors as to the fact that development of the reserves in the Camp Hill field would far exceed five years. In our disclosure regarding Camp Hill in our 2005 Form 10-K, which was submitted to the Staff in advance of filing on February 22, 2006, we explained, “To fully develop the [Camp Hill] field, we expect to drill approximately 326 wells from 2006 through 2017.” Our filings have subsequently been updated to |
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report drilling activity and inform investors that drilling in the Camp Hill field is expected to continue through 2024, with 244 wells remaining to be drilled. (See 2008 Form 10-K/A, page 12.) We believe that during our correspondence and discussions with the Staff in 2005-06, we were explicit as to the long-term nature of the development plan for the Camp Hill field. It was our belief at the time of the 2005-06 review, and remains so, that there is no bright-line “five-year” rule, particularly as applied to a tertiary steam drive project in a well-established structurally understood heavy oil field such as the Camp Hill field. We respectfully submit that it would be inconsistent and confusing to investors to now take an approach that the Camp Hill field reserves must be written off as being too far in the future, particularly since our development activities have significantly accelerated since 2005 and will accelerate further in the next four to six weeks as we recommence steam injection into more than twice as many patterns (14) as have been produced from in the recent past, with a commensurate increase in production rates. |
Current rules allow a 15-year development plan. | ||
The five-year timeframe for development of proved undeveloped reserves is currently an informal and generally inconsistently applied industry rule of thumb and not an accepted, binding bright-line industry or engineering rule and is not part of any existing SEC rule. As noted in Concept Release No. 33-8870, the current definition of proved undeveloped reservesdoes “not specify a period of timeduring which a company should expect to commence drilling the new well or the period of time in which a company will incur a relatively major expenditure.” (Release No. 33-8870, Section II; emphasis added.) |
The Staff has allowed even longer steam flood development plans for others. | ||
As discussed below, while we have the ability to control much of the pace of development, we have specific reasons based largely on operational and economic efficiency and health, safety and environmental concerns, for choosing a development plan that is expected to span 15 years. Many of these reasons are inherent in the nature of a heavy oil (19 API) tertiary steam drive project, which typically results in a time period for development that far exceeds five years. In that regard, we note that, in the Staff’s letters to Plains Exploration & Production Company dated June 19, 2008 and July 28, 2008, the Staff, in commenting on that company’s proved undeveloped reserves, including the San Joaquin Valley and Arroyo Grande steam operations, stated: |
“Based on this rate of development it will take you almost 17 years to just develop these reserves let alone actually produce them.” (June 27, 2008 letter) and “The continuation of this trend will result in the monetization of your PUD reserves only after 10 to 20 years of development.” (July 28, 2008 letter)
We note that the Staff did not insist that Plains’ proved undeveloped reserves be written off, despite the fact that their development would require more than the 15 years contemplated for our properties in the Camp Hill field. |
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However, and notwithstanding our ability to execute a development plan at a pace that is faster than what we have pursued in the past, there are specific reasons that we have not done so to this point and, correspondingly, have not adopted a faster development plan than we deem currently appropriate to maximize the profitability of the project, nor have we attempted to include such a plan in our reserve calculations. | ||
Specifically, the development plan that we are currently following is typical for a tertiary steam drive project for a heavy oil field. In these projects, as in the Camp Hill field, the optimal balance between capital pre-investment (in drilling and construction of steaming facilities) requires us to commence steaming in a portion of the field and then, as the reservoir in that portion of the field reaches optimal production temperature, to reduce injection in that portion of the field and commence steaming in adjacent patterns, building the steam process out across the field. | ||
In keeping with our current development plan, we have also sized our water sources, generator capacity, steam lines and water disposal capacity to optimize our current estimate of field economics. While each of these capabilities is scalable(e.g.,our current development plan consists of steaming with one steam generator within the next four to six weeks, potentially supplementing it with a portable steam generator that we have recently rebuilt, and adding a third steam generator in 2010), using additional equipment does not improve recovery efficiency and does not necessarily translate to improved economic return due to the increased upfront capital required to increase development. | ||
The development economics of the Camp Hill field are extremely sensitive to capital investment and the differential of oil to gas pricing. We have consistently represented this project to be a long-term development opportunity, as are most tertiary steam drive projects, but we remain flexible to accelerating development when the optimal economic conditions arise. The shallow depth of the oil accumulation and its rural location limit the economically viable service sector to select small local vendors who have limited equipment inventory. We have largely kept these vendors busy over the last couple of years preparing for the steam initiation project underway. Bringing in services outside the area has generally proven not to be a cost-effective way to develop the field. | ||
Health, safety and environmental concerns also impact the pace of our development plans. The Camp Hill field is located in a rural portion of East Texas. Although we have all currently necessary air quality permits, and operate within local, state and federal regulations, increasing the pace of development and operating additional steam generators would increase heat, carbon dioxide and particulate point source pollution, and would also require us to obtain additional “point source” air pollution permits from the State of Texas. | ||
For the specific reasons stated above, we would respectfully submit that a tertiary steam drive development plan in the Camp Hill field that is expected to last 15 years is reasonable, appropriate and consistent with existing Commission rules and established precedent in the industry. |
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Our current 15-year development plan is consistent with the newly adopted rules. | ||
In addition, we believe that our proved undeveloped reserves in the Camp Hill field meet the new definition of proved undeveloped oil and gas reserves adopted by the Commission in Final Rule Release No. 33-8995, “Modernization of Oil and Gas Reporting.” That release, at Section II.F.2., seems to address the very point at issue in this matter: |
Many commenters opposed the proposed language that would have imposed a five-year limit on maintaining undeveloped reserves unless “unusual” circumstances existed. They asserted that large projects, projects in remote areas, and projects in continuous accumulations, such as oil sands, typically take more than five years to develop, but they do not view such projects as “unusual.” One commenter noted that the proposed rule is not consistent with the PRMS, which uses the term “specific circumstances,” rather than “unusual circumstances.” Other commenters suggested that we require the company to explain why it has not developed any undeveloped reserves for more than five years. The intent of the proposal was not to exclude projects that typically take more than five years to develop from being considered reserves.We agree that the rule should allow the recognition of reserves in projects that are expected to run more than five years, regardless of whether “unusual” circumstances exist.Therefore, we have revised the rule to replace the term “unusual” with the term “specific.” (footnotes omitted; emphasis added).
As we discussed during our conference call and as explained above, we have purposefully chosen to develop our properties in the Camp Hill field under our currently contemplated schedule based on specific circumstances, including the slow production increase of wells in this type of formation before steaming, the decision to develop the properties in the most efficient and therefore profitable manner (even if not the fastest) by staging capital expenditures, optimizing the capacity of water source, steam lines and water disposal equipment, by using a limited, but scalable, number of steam generators running at full capacity, and by operationally optimizing the systematic flooding of steam patterns for efficient development before moving on to other patterns, and air and noise quality and safety issues with bringing additional generators, drilling rigs and other equipment into and out of the field. | ||
Management believes its current plan is the most efficient way to produce the field and the most profitable use of our existing infrastructure. We acknowledge that it would be possible to use a different development plan that could result in a more rapid pace of development of our reserves, including through the acquisition of significant amounts of additional equipment, additional infrastructure and additional personnel; indeed, it is theoretically possible to add an almost unlimited amount of all such resources. This would not, however, be the most efficient way to develop the field. We similarly acknowledge that it is our choice to adopt a development plan that does not result in the development of the field in five years or in the fastest theoretical time. We respectfully |
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disagree with the Staff’s suggestion that this choice renders the reserves non-proven because “special circumstances” would not exist as a result of a company’s decision to pursue a slower growth pattern in order to make the development more profitable, safe and environmentally sound. We respectfully contend that neither the current nor newly adopted SEC rules require a company to develop properties using the fastest method possible (or even a method that ensures development within five years) in order to classify undeveloped reserves as proved. Such a requirement could be applied to almost any development project by an oil and gas company, because the development of a field involves innumerable choices. Such an approach would create unproductive incentives and in any event, has, to our knowledge, never been seen as a portion of the current or the newly adopted rules. |
Additionally, as quoted above, the adopting release for the newly adopted rules indicates that the Commission was mindful that certain types of projects would take longer than five years to develop but which should nevertheless be deemed proved undeveloped. As pointed out in the letter from Nexen to the Staff dated September 5, 2008 that was referred to in the adopting release, “Similarly, oil sands projects typically have a 40-plus year life and over three-quarters of the reserves relate to wells that won’t be drilled in the first five years.” We respectfully submit that there is no significant difference between tertiary steam floods and oil sands projects for these purposes and that the Camp Hill situation is precisely the type of project that was contemplated by the Commission in not adopting a bright-line five-year test for proved undeveloped reserves. Lastly, the adopting release specifically states that the circumstances requiring a greater than five-year period for development do not even need to be “unusual,” but only “specific.” For the reasons stated above, we strongly believe that the circumstances causing our development plan to extend more than five years are both specific and not unusual and the reserves are therefore “proved undeveloped reserves” under the newly adopted rules. |
We note that the newly adopted rules will require disclosure regarding why such undeveloped reserves have not been developed within five years. Although our periodic reports already contain this and other information about the development of the Camp Hill field (see, e.g., page 24 of our 2008 Form 10-K/A), we are fully amenable to adding additional disclosure that the Staff deems appropriate and helpful to an investor to make this point even clearer. | ||
Carrizo’s proposed application of the newly adopted rules at year-end December 31, 2009. | ||
For all the reasons stated above, we continue to contend that not only was it entirely appropriate to book the proved undeveloped reserves under existing Commission rules and circumstances on December 31, 2008, but that specific circumstances did and continue to exist in the development of the Camp Hill field that would permit us to maintain those proved undeveloped reserves under the newly adopted rules. | ||
However, we also understand from the Staff’s statements on our conference call, that in its view the newly adopted rules could be interpreted to prospectively impose a more difficult threshold to maintaining certain of our proved undeveloped reserves at Camp |
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Hill because the new rules were adopted by the Commission and contemplate a five-year limit absent specific circumstances, whereas the existing rules rely upon Staff initiatives in employing a five-year limit. | ||
We respectfully disagree with the Staff’s interpretation of the new rules. However, if after considering the information provided in this submission, should the Staff insist that “specific circumstances” (under the newly adopted rules to be effective December 31, 2009) do not apply to the Camp Hill field reserves that are currently categorized as proved undeveloped reserves beyond a five-year term, then we propose that, in connection with the application of the new rules at December 31, 2009, we will revise our reporting such that undeveloped reserves in the Camp Hill field that cannot be developed within five years will no longer be classified as proved until our third-party reserve engineers determine that they can be developed within that time frame. While we cannot currently estimate the precise impact of this decision due to the variables inherent in estimating future engineered reserves, we would currently anticipate that this reclassification will lead to a negative revision in our Camp Hill field proved reserves of approximately 4.0 to 5.0 million barrels (24 — 30 Bcfe) as of December 31, 2009. The primary factor impacting this range of revisions would be whether or not we decide to accelerate our current field development plan as a result of the production response to our steam injection that is scheduled to commence in the next few weeks. If no change in the current development plan is made, we would currently expect the negative revision to be towards the upper end of the range that we have cited above. |
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