May 17, 2006
By EDGAR and by fax (202) 772-9369
Mr. H. Roger Schwall
Assistant Director
Division of Corporation Finance
United States Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C.
20549-7010
| Re: | Letter dated May 4, 2006 to St. Mary Land & Exploration Company | |||
| Form 10-K for the fiscal year ended December 31, 2005 |
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| Filed February 27, 2006 |
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| File No. 1-31539 |
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Dear Mr. Schwall:
Please find our response to the above captioned comment letter dated May 4, 2006. As a courtesy, we have reproduced the applicable portion of the letter in our responses. The comments are in bold text and our responses are incorporated within the document in normal text:
Accounting Comments
Form 10-K for the Fiscal Year Ended December 31.2005
Properties
Mr. Roger Schwall
Securities and Exchange Commission
May 17, 2006
Page 2
1. With regard to your disclosures of "PV-10 value," "Reserve replacement -including sales," and "Reserve replacement - excluding sales" on page 24 and elsewhere in your filing, please note that we consider these to be non-GAAP measures. As such, they must be accompanied by the appropriate disclosure required by Regulation S-K, Item 10(e). Your disclosure should include, among other things, a reconciliation to the most directly comparable GAAP measure. In the case of "PV-10 value," we consider the standardized measure of future net discounted cash flows, as set forth in paragraph 30 of SFAS 69, to be the most directly comparable GAAP measure.
With regard to your reserve replacement measures, please:
| • | Describe how the ratios are calculated. We would expect the information used to calculate these ratios to be derived directly from the line items disclosed in the reconciliation of beginning and ending proved reserve quantities, which is required to be disclosed by paragraph 11 of SFAS 69. |
| • | Identify the status of the proved reserves that have been added (e.g., proved developed vs. proved undeveloped). It is not appropriate to calculate these ratios using: |
| • | non-proved reserve quantities, or, |
| • | proved reserve additions that include both proved reserve additions attributable to consolidated entities and investments accounted for using the equity method. |
| • | Identify the reasons why proved reserves were added. |
| • | The reconciliation of beginning and ending proved reserves, referred to above, includes several line items that could be identified as potential sources of proved reserve additions. Explain to investors the nature of the reserve additions, and whether or not the historical sources of reserve additions are expected to continue, and the extent to which external factors outside of managements' control impact the amount of reserve additions from that source from period to period. |
| • | Explain the nature of and the extent to which uncertainties still exist with respect to newly discovered reserves, including, but not limited to regulatory approval, changes in oil and gas prices, and the availability of additional development capital and the installation of additional infrastructure. |
Mr. Roger Schwall
Securities and Exchange Commission
May 17, 2006
Page 3
| • | Indicate the time horizon of when the reserve additions are expected to be produced to provide investors a better understanding of when these reserve additions could ultimately be converted to cash inflows. |
| • | Disclose how management uses these measures |
| • | Disclose the limitations of these measures. |
Please note that we specifically discussed the reserve replacement disclosure with Mr. Schwall and Mr. Murphy last year on April 11 and 12, 2005, in connection with the response to the Staff’s comment letter dated March 24, 2005, with respect to our 2004 Form 10-K, and we believed that we had resolved the Staff’s desired form of disclosure of such items through changes made to the presentation of such items in the 2005 Form 10-K. We documented the agreed conclusions from the aforementioned telephone conversation in a letter dated April 27, 2005, which was addressed to Mr. Murphy.
We believe that the Form 10-K is an integrated document and that each section supports another, accordingly, we have disclosed in a variety of locations how the calculations work, why we believe these measures are relevant and how they are useful to a reader. The view we have taken is that the Form 10-K document would be unnecessarily redundant if we included the descriptive nature and justification for using these measures at each place in the document they are used. Arguably, these measures are operating measures that would normally be excluded from the definition of a non-GAAP financial measure. With regard to the disclosure of the Reserve Replacement – Including Sales and Reserve Replacement – Excluding Sales we direct the SEC Staff’s attention to the following areas of our Form 10-K filing.
| • | Page 11 – The definitions of the measures as well as the method for calculating the resulting percentages. |
| • | Page 2 – A description of the resulting percentage measures in the context of how our reserves had changed during the year, as well as what components of our reserve replacement came from organic drilling operations and by acquisitions. Included in this section is relevant discussion of where the largest reserve additions were to the Company. |
| • | Page 24 – The measures are disclosed in the table of Proved Reserve Data. This disclosure provides the regulatory required items plus those measures that we believe to be important for measuring and benchmarking our performance. These measures are displayed with equal prominence to other data provided in the table as not to imply that the supplemental measures are more or less important than another. |
Mr. Roger Schwall
Securities and Exchange Commission
May 17, 2006
Page 4
| • | Page 34 – The MD&A disclosure includes management’s goals as related to reserve replacement, how we believe a 200 percent reserve replacement is important for growing net asset value per share, and then we describe how St. Mary has performed against those goals. This information is included in our disclosures, because we believe they are important metrics to understand the performance of our operations. Accordingly, we provided the information to the readers of our Form 10-K. These disclosures represent management’s belief as to why the presentation of these measures provides useful information to investors regarding our asset base, which then provides a basis for assessing the Company’s performance and financial condition. |
We confirm that these measures are calculated using only proved reserves. We also note for the Staff’s understanding, that St. Mary has fully consolidated each of its subsidiaries and that it does not have any ownership structures that would provide for any percentage of reserves from entities using the equity method of accounting. Accordingly, the calculation of the reserve replacement metrics can be calculated directly from the line items in the oil and gas disclosures on page F-31.
Related to the time horizon over which the reserve additions are expected to be produced, reserves have been added as a result of drilling activity (including proved developed and proved undeveloped reserves) and acquisitions. Our additions have been in geographic areas where St. Mary had previously established core areas of operations and these reserve additions do not have substantially different characteristics than the existing assets. Please note the reserve life referenced in the Proved Reserves Data table on Page 24 which increased slightly over the last three years, indicating that the proved reserve additions are similar in character to the pre-existing proved reserves. Our Proved Undeveloped (“PUD”) Reserves increased from 15 percent to 18 percent of total proved reserves, indicating that a higher percentage of the proved reserves are currently undeveloped, and thus, will require a slightly longer time horizon to be produced. We believe that the disclosures in the first full paragraph on page 2 of the Business section as well as in the second paragraph of the Reserve Replacement and Growth topic covered in the opening section of our MD&A on pages 34 and 35 describing the increase in the PUD percentage provide a clear description of the location and factors related to the increase in the PUD percentage.
Mr. Roger Schwall
Securities and Exchange Commission
May 17, 2006
Page 5
As to the reconciliation of the PV-10 value disclosure, we have a definition of this measure on page 10 of our Form 10-K. The definition describes that it is being used as an “indicative representation of the relative value of the Company” so that it can be used as a comparison to other companies. Since we emphasize that this measurement is indicative towards measuring we do not believe that any further mitigating language is necessary for the disclosure. As you can see on page 24 in the Reserves section, we are not using this measure in lieu of the standardized measure of discounted future net cash flows; rather we are using it in addition to this GAAP defined measure. In terms of providing a reconciliation between the two measures, we believe that a reconciliation is not incrementally meaningful as the components of the calculation are fully described and the result is explicitly provided by the Company. In addition, there are no complex or unusual reconciling items. Therefore, we believe that a reasonably prudent reader can understand the difference between the two measures and reconcile the number without difficulty.
We do recognize the requirement of Regulation S-K, Item 10(e)(1)(i)(B) and note that St. Mary will prospectively include a tabular presentation as a footnote to the Reserves section on page 24 that presents the reconciliation between the PV-10 value measure and the standardized measure. We do not believe that the presentation in our Form 10-K, as it currently is presented is misleading or would cause a reasonably prudent reader to misunderstand St. Mary’s business, oil and gas reserves, asset base, financial position or results of operations. Accordingly, we respectfully request that the tabular presentation be included on a prospective basis only.
Lastly, with regard to disclosure as to uncertainties about reserve additions we refer the SEC Staff to our existing risk factors disclosures on page 12 titled -If we are not able to replace reserves, we will not be able to sustain production; and, The actual quantities and present value of our proved oil and gas reserves may be less than we have estimated; as well as on page 14 titled – Exploration and development drilling may not result in commercially productive reserves and Future oil and gas price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying value on page 15. We believe that these disclosures, together with the Cautionary Information about Forward Looking Statements section beginning on page 7, allow a reader to be adequately aware of the risks to the industry as a whole as well as specifically to St. Mary. In the Reserve Replacement and Growth caption of our MD&A we talk about aberrations from period to period and why we believe that multi-year measures are more representative of the performance of companies in our business. We also point out to the SEC Staff that over the three years ended 2003, 2004 and 2005 our net revision is an upward 37.2 BCFE adjustment. Relative to our yearend reserves at each of the aforementioned period yearends, the revision line has represented less than 4.3 percent of the total period end reserve quantities. As such, we do not believe that the change from the revision line is of such a size to warrant any additional disclosure.
Mr. Roger Schwall
Securities and Exchange Commission
May 17, 2006
Page 6
Engineering Comments
Form 10-K for the Fiscal Year Ended December 31, 2005 General
2. | Please provide a copy of your 2004 and 2005 reserve reports. Also provide a copy of the reserve reports that includes the determination of the unproved reserves reported in your press release dated January 26, 2006. |
The requested reports were supplementally submitted to Mr. Murphy of the Staff for delivery on May 17, 2006.
3. | Please tell us if you attributed proved reserves to locations that are not adjacent to productive wells. Submit to us the engineering and geologic justification for PUD reserves you have claimed that are not in legal, technically justified locations offsetting (adjacent to) productive wells. Otherwise, affirm to us that none of your claimed PUD reserves are attributed to such locations. |
We confirm that with the exception of the coalbed methane (“CBM”) reserves in the Powder River Basin described in the next paragraph, that our PUD reserves are adjacent to existing productive wells.
In the CBM project area in the Powder River Basin, PUD reserves have been booked in sections offsetting sections of proved developed producing reserves. As of December 31, 2005, we had recorded 4 BCF of PUD reserves related to these CBM reserves of the total 794 BCFE of proved reserves for the Company. Although a portion of these PUD locations are not immediately offsetting productive wells, these sections have demonstrated with certainty that continuity of production exists as described based on the following criteria.
Mr. Roger Schwall
Securities and Exchange Commission
May 17, 2006
Page 7
To categorize the CBM locations as proved reserves, the Company and NSAI, the Company’s independent reserve evaluator for the Powder River Basin properties, require adequate documentation regarding (1) geologic lateral continuity of the coal members, (2) pressure data to confirm continuity of the coals, (3) test or production data, from any wells in the section or offsetting section regardless of operator, to establish the coal permeability and the capability of the coals to produce gas, (4) sufficient gas content data, and (5) commerciality of existing operations and planned future development. Even though the guidelines suggested by the Securities and Exchange Commission are restrictive on this issue, the Company and NSAI are of the opinion that the Powder River Basin represents one of the few examples in the United States where proved undeveloped reserves can be assigned beyond one direct offset spacing unit due to the demonstration of pressure communication (reservoir connectivity) over large distances as shown by water level tracking. This is only done in selected areas where coal continuity is established by existing well control and where pressure and permeability is established based on pressure and production information. Also, the offset or reference well for a PUD location assignment must be to an acceptable peak gas rate to support commerciality and to clearly support depletion of the assigned volumetric reserves for the spacing unit (either 80 or 160 acres). The producing well that establishes PUD reserves for an area may not necessarily be owned by St. Mary. The determination and classification of these reserves as proved is a case-specific decision based on the data available. Business, page 1
Significant Developments since December 31, 2004
4. | According to FASB 69 paragraph 30, revisions should include reserve additions from development drilling. We note your reserve revisions of 33.9 BCFE represent about a 5.5% increase over 2004 reported reserves volumes. This seems inconsistent with your statement that you added 140 BCFe from your drilling program. Please advise us if you include reserve additions from development drilling as revisions. |
Our disclosure on page 4 is reproduced below:
“Increase in 2005 Year-End Reserves. Proved reserves increased 21 percent to 794.5 BCFE at December 31, 2005, from 658.6 BCFE at December 31, 2004. We added 140.1 BCFE from our drilling program, 49.8 BCFE from acquisitions, and 33.9 BCFE from upward reserve revisions. Included in the revision number is 23.1 BCFE of upward revisions resulting from increases in oil and gas prices. We sold properties with reserves of less than one BCFE in 2005.”
St. Mary discloses changes in its reserve quantities in accordance with paragraph 11 of FASB 69. The 33.9 BCFE disclosed in the revision line includes “......changes in previous estimates of proved reserves, either up or downward, resulting from new information (except for an increase in proved average) normally obtained from development drilling and production history or resulting from a change in economic
Mr. Roger Schwall
Securities and Exchange Commission
May 17, 2006
Page 8
factors” as described in Paragraph 11.a. to FASB 69. Paragraph 11.a. clearly states that changes to the previous estimates are all that is included in the Revision of previous estimate line, as such, the change in reserves from a prior years’ estimate is all that is captured in this line.
The 140.1 BCFE represents extensions and discoveries related to drilling and are comprised of additions to our proved reserves for 2005 related to both development and exploratory drilling capital expenditures in the current year as well as new reserves that were added through the Company’s operations. We believe that the reserve additions resulting from the expenditures related to new reserve cases added in the current year is what properly belongs in the Extension and discovery line item. The Revision of previous estimate line is comprised of revisions that come simply from revision of estimates due to performance changes, revisions due to gaining new information about well performance, and resulting changes in reserves due to changes in economic circumstance. It is important to understand that included in the Revision of previous estimate line are revisions related to reserve cases that existed in prior years, revisions from ownership interests in wells newly acquired in the current year as well as in the prior year. Therefore, we believe it would be inappropriate to classify the revision line as related to current year operations. As such, we believe that our existing disclosure is accurate and does not require modification.
Risk Factors, page 11
The actual quantities and present values of our proved oil and gas reserves page 12
5. | Revise to indicate how many of your reserves were proved developed non-producing as of December 31, 2005. |
Our proved developed non-producing reserves as of December 31, 2005, comprise 116.7 BCFE of the total 648.9 BCFE of proved developed reserves. We recognize that although this is not a required disclosure, it does provide incremental context to our risk factor disclosure. We note that we will provide this additional disclosure in future filings.
Properties, page 20 Reserves, page 24
6. | You state that Ryder Scott and Netherland, Sewell & Associates prepared your reserves. With a view towards possible disclosure explain to us the meaning of the term "prepared." Tell us if they provided independent petrophysical analysis, geological mapping and decline curve analysis as part of their evaluation and if they utilized all of that work in the final reserve estimates. Provide us with the level of input, if any, that the company contributed to their work. |
We have reproduced the disclosure referred to on Page 24 of our Form 10-K below:
Mr. Roger Schwall
Securities and Exchange Commission
May 17, 2006
Page 9
“The following table presents summary information with respect to the estimates of our proved oil and gas reserves for each of the years in the three year period ended December 31, 2005. The table includes reserves prepared by independent petroleum engineering firms, Ryder Scott Company and Netherland, Sewell & Associates, Inc., and us. For the periods presented, Ryder Scott Company and Netherland, Sewell & Associates, Inc., evaluated properties representing a minimum of 80 percent of the total PV-10 value of our reserves. The proved oil and gas reserves prepared by Netherland Sewell in 2004 and 2005 consist of the coalbed methane development at Hanging Woman Basin as well as our non-operated interest at Atlantic Rim. The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by St. Mary. Neither prices nor costs have been escalated. You should read the following table along with the section entitled “Risk Factors – Risks Related to Our Business – Estimates of oil and gas reserves are not precise.”
Pursuant to your question related to the preparation of the estimates of our proved oil and gas reserves, we indicated on Page 24 that the reserves were “prepared by independent petroleum engineering firms, Ryder Scott Company and Netherland, Sewell & Associates, Inc. and us.” We believe this to be a very literal use of the word prepared and we believe that the term is appropriately based on the description, that will follow, of the process we go through in preparing the reserves to be disclosed in our Form 10-K.
We believe that the use of the word “prepared” is literally accurate, particularly when taken in context with the phrase in the next sentence of our disclosure that “For the periods presented, Ryder Scott Company and Netherland, Sewell & Associates, Inc., evaluated properties representing a minimum of 80 percent of the total PV-10 value of our reserves.” We believe that we are presenting to the readers of our Form 10-K that we use the reserve calculations as prepared by Ryder Scott and NSAI that represent 80 percent of the value of our reserves. We want to make sure that we present to a reader that we and our third party reserve engineering firms stand behind the calculations and that we have achieved a level of review that is distinctly different than simply an acceptance by the third party reserve engineering firm of the reserve engineering prepared by the Company. This language is intended to distinguish that there is a difference between having reserves prepared and having them audited by a third party engineering firm. We believe that there is precision to the language used in the first sentence of each Ryder Scott’s and NSAI’s letter to the Company.
To help highlight why we believe the disclosure is accurate and not misleading, the following describes the mechanical process we go through in preparing the reserves. St. Mary personnel determine estimates of the oil and gas reserve quantities and values of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known
Mr. Roger Schwall
Securities and Exchange Commission
May 17, 2006
Page 10
reservoirs. Our Manager of Reservoir Engineering coordinates the reserve estimate process with Regional Coordinators who initiate the reserve estimation process within their respective regions. Documentation for the basis of our conclusions is sent to Ryder Scott personnel for an assessment of the preponderance (approximately 80% by value) of the Company’s non-CBM oil and gas reserves. NSAI coordinates with St. Mary personnel to obtain well and lease information, then provides an assessment of all of the Company’s Powder River Basin and Green River Basin CBM reserves.
In addition to the data provided by St. Mary, these third party reservoir engineering firms call upon public data sources in addition to their internally generated studies and reports to conduct independent assessments of the properties that they evaluate. The engineering firms generate independent petrophysical analysis, geological mapping and decline curve analysis as part of their evaluation when necessary. For 80 percent of the value of the Company’s reserves, the reserve estimates provided by these engineering firms are used in the Form 10-K disclosure, rather than the reserve estimates prepared by the Company. Clearly there is an interaction between each group in utilizing information provided from one to the other; however, this is a bi-directional process which we believe provides a valuable tool to more accurately estimate the Company’s proved oil and gas reserves.
St. Mary’s Manager of Reservoir Engineering compares, on a property-by-property basis, the reserve estimates calculated by the third party reservoir engineering firm to the reserve estimates calculated by St. Mary. If significant variances exist, then additional review with the third party reservoir engineering firm is pursued to ensure that data and interpretational items were performed consistently or to determine why differences exist between the two databases. In the event a discrepancy is not resolved between St. Mary and the third party engineering firm as to the reserve profile, the third party engineering estimate of reserves is utilized in the disclosure.
Acreage, page 27
| 7. | You state that developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation. Based on the total net developed acreage of 407,322 acres and the total net wells of 1,522 the average spacing per well is over 260 acres. This appears to be high for oil and gas fields located onshore in the United States. Please reconcile this for us. |
We maintain an accounting system in which we are able to identify well locations and acreage; it is from this system that we generate these numbers. In preparing the Form 10-K we are aware of the disclosure requirements of Industry Guide No. 2 related to acreage and well count disclosure and we believe that we have disclosed accurate information.
Mr. Roger Schwall
Securities and Exchange Commission
May 17, 2006
Page 11
We classify productive wells as either producing wells or wells capable of commercial production although currently shut in. One or more completions in the same wellbore are counted as one well. Each productive well in a multi-well unit (that may be evaluated as a single entity for reserve evaluation) is counted individually for purposes of this well count.
Our operations are predominately in Rocky Mountain and Mid-Continent states where typical well spacing is larger than the 260 acre number referred to in your comment. The table below illustrates the specific calculation in states where we hold substantial acreage:
| North Dakota | 94,791 net acres | 340 net wells | 279 acres per well |
| Wyoming | 92,424 net acres | 399 net wells | 231 acres per well |
| Oklahoma | 81,336 net acres | 292 net wells | 279 acres per well |
We believe that the measure of average spacing per net well can provide a basis for some high level analysis, however, one needs to consider the composition of a company’s specific operations. Each company, depending on their unique acreage and well ownership structures will yield a different calculated number.
Press Release Dated January 26, 2006
8. | We note your press release dated January 26, 2006 announcing year-end 2005 reserves. Please explain to us the source of the unproved definitions and the definitions themselves that you utilized. Provide the basis for these estimates. |
The source of the unproved reserve definitions utilized in the preparation of estimated amounts of unproved reserves disclosed in the press release dated January 26, 2006, which definitions were briefly summarized along with a brief summary of the definition of proved reserves under the caption “Information About Reserves” at the end of the press release, was the Petroleum Reserves Definitions approved by the Society of Petroleum Engineers (“SPE”). Such unproved reserve definitions are located on the SPE’s Internet website at www.spe.org. The complete text of such definitions, including general examples of what unproved reserves may include, is attached hereto as Exhibit A. The basis for the estimated amounts of unproved reserves disclosed in the press release is included in the reserve reports supplementally submitted to Mr. Murphy in response to Comment 2.
In connection with our responses to the Staff’s comments, the Company acknowledges that:
| • | the Company is responsible for the adequacy and accuracy of the disclosure in the filing; |
Mr. Roger Schwall
Securities and Exchange Commission
May 17, 2006
Page 12
| • | staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and |
| • | the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
Thank you for your consideration of our explanations and our proposal to enhance future disclosures.
Please contact me at (303) 863-4334 with any further questions.
Best Regards,
/S/ DAVID W. HONEYFIELD
David W. Honeyfield
V.P. – Chief Financial Officer, Secretary & Treasurer
cc: | James Murphy, SEC Petroleum Engineer |
Dwight Landes, Ballard Spahr Andrews & Ingersoll, LLP
| Dennis Boylan, Deloitte & Touche, LLP |
Exhibit A
Definitions of Unproved Reserves
FROM PETROLEUM RESERVES DEFINITIONS
APPROVED BY SOCIETY OF PETROLEUM ENGINEERS
(Extracted from http://www.spe.org/spe/jsp/basic/0,2396,1104_12169_0,00.html)
Unproved Reserves
Unproved reserves are based on geologic and/or engineering data similar to that used in estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. Unproved reserves may be further classified as probable reserves and possible reserves.
Unproved reserves may be estimated assuming future economic conditions different from those prevailing at the time of the estimate. The effect of possible future improvements in economic conditions and technological developments can be expressed by allocating appropriate quantities of reserves to the probable and possible classifications.
Probable Reserves
Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.
In general, probable reserves may include (1) reserves anticipated to be proved by normal step-out drilling where sub-surface control is inadequate to classify these reserves as proved, (2) reserves in formations that appear to be productive based on well log characteristics but lack core data or definitive tests and which are not analogous to producing or proved reservoirs in the area, (3) incremental reserves attributable to infill drilling that could have been classified as proved if closer statutory spacing had been approved at the time of the estimate, (4) reserves attributable to improved recovery methods that have been established by repeated commercially successful applications when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics appear favorable for commercial application, (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and the geologic interpretation indicates the subject area is structurally higher than the proved area, (6) reserves attributable to a future workover, treatment, re-treatment, change of equipment, or other mechanical procedures, where such procedure has not been proved successful in wells which exhibit similar behavior in analogous reservoirs, and (7)
incremental reserves in proved reservoirs where an alternative interpretation of performance or volumetric data indicates more reserves than can be classified as proved.
Possible Reserves
Possible reserves are those unproved reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves. In this context, when probabilistic methods are used, there should be at least a 10% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible reserves.
In general, possible reserves may include (1) reserves which, based on geological interpretations, could possibly exist beyond areas classified as probable, (2) reserves in formations that appear to be petroleum bearing based on log and core analysis but may not be productive at commercial rates, (3) incremental reserves attributed to infill drilling that are subject to technical uncertainty, (4) reserves attributed to improved recovery methods when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics are such that a reasonable doubt exists that the project will be commercial, and (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and geological interpretation indicates the subject area is structurally lower than the proved area.
