June 1, 2015
H. Roger Schwall
Assistant Director
Office of the Chief Accountant
United States Securities and Exchange Commission
100 F Street, N. E.
Washington, D.C. 20549
| Re: | Atlas Resource Partners, L.P. |
Registration Statement on Form S-3
Filed May 1, 2015
File No. 333-203800
Form 10-K for the Fiscal Year Ended December 31, 2014
Filed March 2, 2015
File No. 1-35317
Dear Mr. Schwall:
A copy of this letter has been furnished through EDGAR as correspondence.
On behalf of Atlas Resource Partners, L.P. (“Atlas Resource”), this letter responds to the Staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) in its letter of comment, dated May 22, 2015, with respect to the above-referenced filings (the “Comment Letter”). For your convenience, the comments provided by the Staff have been repeated in bold type exactly as set forth in the Comment Letter and the response on behalf of the Atlas Resource is set forth immediately below the text of the applicable comment.
Registration Statement on Form S-3
| 1. | Please be advised that we will not be able to accelerate the effectiveness of your registration statement until you have cleared all comments on your periodic reports. |
Response: Atlas Resource acknowledges the Staff’s comment.
Letter to H. Robert Schwall
June 1, 2015
Form 10-K for Fiscal Year Ended December 31, 2014
Item 1: Business, page 8
Drilling Activity, page 18
| 1. | Please expand the disclosure related to your drilling activity provided on here and elsewhere on page 73 to clarify the number of gross and net dry wells drilled for each of the periods presented. Refer to the disclosure requirements pursuant to Item 1205 of Regulation S-K. |
Response: Atlas Resource notes to the Staff that no gross or net dry wells were drilled during the periods presented and will indicate as such in future filings.
| 2. | We also note your disclosure of “wells turned in line” provided in conjunction with the tabular presentation of your drilling activity. Please expand your disclosure to clarify the meaning of this term. |
Response: Atlas Resource acknowledges the Staff’s comment and proposes to add the following definition of “wells turned in line” in future filings.
“Wells turned in line refers to wells that have been drilled, completed, and connected to a gathering system.”
Item 2: Properties, page 58
Proved Undeveloped Reserves (“PUDS”), page 60
| 3. | Please expand your disclosure to explain in more detail the overall net change in the quantities of your proved undeveloped reserves. For example, we have estimated that you had an overall downward change in the net quantities of your proved undeveloped reserves during 2014 of approximately 41.9 Bcfe. However, the difference between your disclosure of positive revisions amounting to 111.5 Bcfe related to drilling and acquisitions and your disclosure of negative revisions amounting to 188.4 Bcfe relating to revisions and the conversion of proved undeveloped reserves to proved developed status does not appear to reconcile the overall change in net reserves. Please expand your disclosure to reconcile the overall change since the end of the prior year to identify and quantity the extent of the changes attributable to material causes, such as revisions of previous estimates, improved recovery, extensions and discoveries, purchases and sales, and quantities converted to developed during the period. Please include details within an accompanying narrative to further clarify the reasons for the changes for each material cause to comply with Item 1203(b) of Regulation S-K. |
Response: Atlas Resource acknowledges the Staff’s comment and proposes the following reconciliation of the changes in proved undeveloped reserves in future filings.
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Letter to H. Robert Schwall
June 1, 2015
Changes in PUDs. Changes in PUDS that occurred during the year ended December 31, 2014 were due to the following:
| • | addition of approximately 64.3 Bcfe due to our acquisitions during the year ended December 31, 2014; |
| • | addition of approximately 50.5 Bcfe due to our drilling activity in the Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls plays; |
| • | addition of approximately 29.2 Bcfe due to Barnett Shale PUDs turning economic; partially offset by |
| • | reduction of approximately 127.3 Bcfe due to the reduction of our five year drilling plans in the Barnett Shale and Marble Falls; |
| • | reduction of approximately 41.2 Bcfe due to the conversion from PUDs to proved developed producing; and |
| • | reduction of approximately 17.4 Bcfe due to basis differential pricing revisions. |
| 4. | Please clarify for us the apparent inconsistency between the 58.4 Bcfe and 30.6 Bcfe in proved undeveloped reserves converted to proved developed status for the periods ending December 31, 2013 and 2012 disclosed in Form 10-K for the fiscal year ending December 31, 2014 and the 117.2 Bcfe and 71.5 Bcfe for these periods disclosed in your Form 10-K for the fiscal year ending December 31, 2013. |
Response: Atlas Resource notes to the Staff that it updated its disclosure in response to comment #10 in the Staff’s comment letter to Atlas Energy Group, LLC on December 5, 2014 relating to Atlas Energy Group’s Registration Statement on Form 10. Atlas Energy Group, LLC, Atlas Resource’s general partner, responded to the Commission’s comment letter on December 15, 2014 and filed a corresponding amendment number 1 to its Form 10.
| 5. | We note the disclosure of 147.2 Bcfe, 77.5 Bcfe and 18.5 Bcfe in negative revisions to your proved undeveloped reserves (“PUDs”) in Form 10-K for the fiscal years ending December 31, 2014, 2013 and 2012, respectively. The revisions for the years ending December 31, 2014 and 2013 are explained as “primarily due to the reduction of our five year drilling plans in the Barnett Shale and pricing scenario revisions.” The revisions for the year ended December 31, 2012 are explained as “primarily due to the reduction of drilling plans in the New Albany Shale formation over the next five years.” Your disclosures indicate that you reversed investment decisions for approximately 39%, 24% and 27% of the PUD reserves disclosed at the beginning of 2014, 2013 and 2012, respectively. |
4
Letter to H. Robert Schwall
June 1, 2015
Please explain in greater detail the reasons for removing PUD locations for the years ending December 31, 2014, 2013 and 2012, and contrast to the reasons for initially booking reserves associated with such locations. Your response should address the following points:
| • | Clarify for us the assumptions and criteria utilized in reaching your final investment decision to develop such locations as well as the facts and circumstances that subsequently altered your development plans. |
| • | To the extent pricing was the reason for your decision to not develop these PUD locations and volumes, please indicate the SEC price utilized at each booking date and at the time the related volumes were subsequently removed. |
| • | For each of the reasons other than price that caused you to remove locations and volumes designated as PUDs, indicate the reason and quantify the related volumes removed, the year this occurred and the year these volumes were initially disclosed. |
| • | Describe for us the procedures that are routinely undertaken in the course of preparing your reserve estimates that are intended to ensure that PUD reserves are only claimed for locations where a final investment decision has been made, and where you are able to demonstrate that the reasonable certainty criteria has been met. |
| • | Describe for us the processes through which changes to previously adopted PUD development plans are taken into consideration in determining that current year PUD volumes meet the reasonable certainty criteria. Specifically address the reasons for disclosing PUD reserves in the Barnett Shale that were subsequently removed in the following year. |
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Letter to H. Robert Schwall
June 1, 2015
Response: Atlas Resource notes to the Staff that the recognition of PUD locations and, in certain instances, the subsequent removal of some locations in the determination of its reserves is the direct result of how Atlas Resource manages its overall business and how the ever changing dynamics of the upstream energy industry, including commodity prices, service provider costs, and the evolution of understanding of geologic characteristics, affect the forward forecasts of its financial results. Management of Atlas Resource continually reviews and adjusts its 5-year forward forecast for many factors, which also impacts Atlas Resource’s decisions and assumptions to develop certain drilling locations. These factors include the following:
| • | Commodity prices – Atlas Resource has significant natural gas, oil and natural gas liquids (“NGL”) production volumes and, as such, is subject to movement in benchmark prices for all such commodities, as well as regional basis differentials at delivery points where Atlas Resource’s commodities are sold. With the vastly different well production profiles of each of Atlas Resource’s basins, movements in individual commodity prices, particularly when certain prices rise while others may fall, will significantly impact expected rates of return on invested well capital between basins. Regional pricing differences for each commodity will also have a significant impact. For example, due to recent oversupply of natural gas in Northeast Pennsylvania and limited availability to move such natural gas to outside markets, certain delivery points have basis differentials of approximately $2 per mcf below the Henry Hub benchmark price. With limited amounts of annual liquidity, which is also impacted by commodity prices, to utilize for capital spending, Atlas Resource is constantly repriortizing the development of PUD locations based upon those wells which will provide the highest rates of return within its 5-year forward forecast. As such, while Atlas Resource is committed to the development of PUDs within its 5-year forward forecast, the development of certain PUDs is subject to constant change, either in the timing over that 5-year period or ultimate development. |
| • | Service provider costs – such costs, including both well development as well as production expenses, have a significant impact on the expected rates of return on invested well capital. In recent years, such costs have experienced significant swings, as significant changes in commodity prices have caused correlating swings in development and production expenses. In addition, the level of development activity in certain basins can cause over- or under-supply of services providers in a particular region, which will have a direct impact on Atlas Resource’s service provider costs. Such changes in service provider costs will have significant impacts on Atlas Resource’s expected rates of return on invested capital and, as such, cause it to reprioritize the development of its PUD locations. |
| • | Geologic characteristics – Atlas Resource develops wells in multiple basins, each of which have their own geologic characteristics which cause the development of such PUDs to have significantly different production profiles. In addition, the consistency of well results within each basin can vary significantly, as geologic characteristics may not be uniform throughout the play. Management of Atlas Resource continually reevaluates the PUD locations within each basin as each new well is drilled. This reevaluation may change the specifications of our drilling or fracking of the next PUD in the development plan, or it may cause us to focus drilling efforts on other PUD locations within the basin that may have better characteristics, based upon current data. Each new well drilled will generally cause Atlas Resource to adjust its drilling plan for PUD development. |
6
Letter to H. Robert Schwall
June 1, 2015
| • | Capital markets – Atlas Resource can only execute its PUD development program to the extent that it has adequate liquidity, both currently available as well as what it can reasonably expect to raise through additional capital market activity, including equity and debt issuances. During periods where capital markets are unavailable or at rates that are uneconomic for further PUD development, Atlas Resource may need to reprioritize and reduce PUD development activity. |
The development and adjustment of Atlas Resource’s 5-year forward forecast is based upon the creation of well drilling development plan for the forecasted period, which is initially prepared by Atlas Resource’s reservoir engineer team based upon available PUD inventory and estimated well rates of return based upon certain estimated commodity prices as well as other assumptions. Such assumptions are reviewed by Management of Atlas Resource, which utilizes such locations and develops the well drilling development plan and resulting forecast based upon many factors, including available liquidity and expected rates of return. At least annually, Atlas Resource’s Board of Directors approves the budget for the upcoming full fiscal year, and reviews the 5-year forward forecast. The PUD development plan for that 5-year forward forecast is the basis for the preparation of Atlas Resource’s year end reserve report. However, prior to the initiation of drilling of any PUD locations within the 5-year forward forecast, Atlas Resource’s Capital Committee, which consists of certain senior members of Management, will review each well’s characteristics, including both operational and financial, and approve its development. If such well does not receive the Capital Committee’s approval, the development plan and the 5-year forward forecast will each be adjusted.
During the year ended December 31, 2013, specific PUD locations within the Barnett Shale were included within Atlas Resource’s 5-year forward drilling plan and were accordingly included within its reserve reports and SEC filings at December 31, 2013. However, in the subsequent fiscal year, several factors changed and, as such, reduced Atlas Resource’s expected development of the Barnett Shale PUD locations within its drilling plan. These included:
| • | Atlas Resource completed its Eagle Ford Acquisition, which included PUD locations in the Eagle Ford Shale that had more favorable rates of return than the comparable Barnett Shale locations; |
7
Letter to H. Robert Schwall
June 1, 2015
| • | Atlas Resource’s Board of Directors approved a reduced well drilling capital budget for fiscal years 2015 through 2019 when compared with the previous five year capital budget based upon lower commodity prices and expected higher cost of capital to fund such development; and |
| • | Barnett Shale well economics were downgraded slightly as a result of higher operating cost assumptions. |
With regards to the negative revisions of 147.2 Bcfe, 77.5 Bcfe, and 18.5 Bcfe during the fiscal years ended December 31, 2014, 2013, and 2012, respectively, Atlas Resources notes the following:
| • | The 147.2 Bcfe negative revision during the year ended December 31, 2014 was primarily the result of 66.8 Bcfe and 60.5 Bcfe of negative revisions to its Barnett Shale and Marble Falls PUD locations, respectively, as a result of changes to its five year drilling plans based on the criteria and process described above. In addition, Atlas Resource notes to the Staff that 19.9 Bcfe of additional PUD locations were removed due primarily to punitive pricing scenarios, as the basis differential of its Lycoming County, Pennsylvania PUD locations continued to unfavorably deviate from first of the month NYMEX pricing; |
| • | The 77.5 Bcfe negative revision during the year ended December 31, 2013 was primarily the result of 56.1 Bcfe of negative revisions to its Barnett Shale PUD locations as a result of more economically punitive pricing scenarios. In addition, 21.3 Bcfe of additional PUD locations were removed due primarily to downgrades of Atlas Resource’s Barnett Shale PUD location spacing; and |
| • | The 18.5 Bcfe negative revision during the year ended December 31, 2012 was primarily the result of negative revisions to its New Albany Shale PUD locations as a result of changes to its five year drilling plans based on comparatively unfavorable well economics when compared with the new PUD locations acquired by Atlas Resource during the year ended 2012. |
| 6. | We note your disclosure stating “as of December 31, 2014, there are no PUDs that had remained undeveloped for five years or more.” |
Please tell us the extent to which the proved undeveloped reserves disclosed as of December 31, 2014 will not be developed within five years since your initial disclosure of these reserves and confirm that you have plans to develop all of the new proved undeveloped locations added as of this date within five years, as is generally required under Rule 4-10(a)(31)(ii) of Regulation S-X.
8
Letter to H. Robert Schwall
June 1, 2015
If any material amounts of proved undeveloped reserves are expected to remain undeveloped for five years or more after your initial disclosure, please disclose the reasons and circumstances to comply with Item 1203(d) of Regulation S-K. For additional guidance on the specific circumstances that justify a period longer than five years, please refer to question 131.03 in the Compliance and Disclosure Interpretations (C&DIs), issued October 26, 2009 and updated May 16, 2013. You may find the C&DIs on our website at the following address:
http://www.sec.gov/divisions/corpfin/guidance/oilandgas-interp.htm
Response: Atlas Resource confirms to the Staff that its proved undeveloped reserves disclosed as of December 31, 2014 are included within its five-year development plan and will be developed within five years of the initial disclosure and proposes to include such disclosure in future filings.
Notes to Consolidated Financial Statements
Supplemental Oil and Gas Information (Unaudited), page 146
| 7. | We note the changes reflected in the line item relating to revisions in the net quantities of your proved reserves for the period ending December 31, 2014 appears to be an aggregation of the changes attributable to two or more separate causes. In this regard, we note the 147.2 Bcfe in downward revisions in your proved undeveloped reserves disclosed on page 60 is significantly more than our calculation of the 49.3 Bcfe in downward revisions in your total proved reserves disclosed on page 147. Please provide us with the net change in reserve quantities, on a disaggregated basis, for each of the underlying causes relating to the revisions in your total proved reserves for the period ending December 31, 2014. To the extent that such changes are individually significant on a disaggregated basis, please expand your disclosure to identify the individual causes and include details within an accompanying narrative to comply with the disclosure requirements pursuant to FASB ASC paragraph 932-235-50-5. |
Response: Atlas Resource notes to the Staff that revisions to total proved reserves during the period are the result of the following:
| • | reduction of approximately 147.2 Bcfe due primarily to the reduction of its five-year drilling plans in the Barnett Shale and Marble Falls and basis differential pricing scenario revisions related to its Lycoming County, Pennsylvania locations; partially offset by |
| • | addition of approximately 54.1 Bcfe related to performance revisions; and |
| • | addition of approximately 42.0 Bcfe related to pricing revisions. |
Atlas Resource proposes to include such disclosure in future filings.
9
Letter to H. Robert Schwall
June 1, 2015
| 8. | Please expand your disclosure of the changes in net quantities of proved reserves for each of the periods presented to include details within an accompanying narrative to further clarify the reasons for the changes related to purchase of reserves in-place. Refer to the disclosure requirements pursuant to FASB ASC paragraph 932-235-50-5. |
Response: Atlas Resource notes to the Staff that purchase of reserves in-place relates to proved reserves purchased through acquisitions during the period and proposes to clarify that in future filings.
Exhibit 99.3
| 9. | The reserves report does not include certain disclosures required by Item 1202(a)(8) of Regulation S-K. Please obtain and file a revised reserves report to include the following information in order to satisfy your filing obligations. |
| • | The disclosure on page 1 states “we evaluated 100% of the Atlas Rangely Weber Sand Unit Acquisition reserves.” However, the reserves report does not relate the reserves evaluated in the report to the proportion of the Company’s total proved reserves pursuant to the disclosure required under Item 1202(a)(8)(iii). |
| • | The disclosure on page 2 does not provide the initial benchmark and realized prices relating to the NGL reserves presented in the report pursuant to the disclosure of the primary economic assumptions under Item 1202(a)(8)(v). |
| • | The disclosure on page 3 states the “report has been prepared for BOLP’s use in filing with the Securities and Exchange Commission.” However, the acronym “BOLP” is not defined and does not appear to correlate to Atlas Resource Partners, LP as referenced elsewhere in the report. Item 1202(a)(8)(i) requires disclosure of the entity for whom the report was prepared. |
Response: Atlas Resource notes to the Staff that it has received an updated reserve report from its third-party reserve engineer and will file the revised report on Form 8-K pending the resolution of this letter. Please see Appendix A for the updated report.
10
Letter to H. Robert Schwall
June 1, 2015
| 10. | We note the reserve report includes information relating to probable reserves that is not disclosed in Form 10-K. We believe the information in the reserve report should correlate with the disclosure in your filing. Therefore, please either obtain and file a revised reserve report which does not include the information relating to probable reserves, or amend the Form 10-K to disclose this information in a manner that is consistent with the guidance in Item 1202(a)(2) of Regulation S-K. |
Response: Atlas Resource notes to the Staff that it has received an updated reserve report from its third-party reserve engineer which excludes references to probable reserves and will file the revised report on Form 8-K pending the resolution of this letter. Please see Appendix A for the updated report.
| 11. | We also note the reserve report refers to additional supplemental information such as an “Appendix” that is not included in Exhibit 99.3. Please obtain and file a revised report to include the referenced supplemental information. Alternatively, remove these references if you do not intend to include this supplemental information in Exhibit 99.3. |
Response: Atlas Resource notes to the Staff that it has received an updated reserve report from its third-party reserve engineer that includes additional supplemental information in an attached appendix and will file the revised report on Form 8-K pending the resolution of this letter. Please see Appendix A for the updated report.
Atlas Resource hereby acknowledges that:
| • | should the Commission or the Staff, acting pursuant to delegated authority, declare the filing effective, it does not foreclose the Commission from taking any action with respect to the filing; |
| • | the action of the Commission or the Staff, acting pursuant to delegated authority, in declaring the filing effective, does not relieve Atlas Resource from its full responsibility for the adequacy and accuracy of the disclosure in the filing; and |
| • | it may not assert Staff comments and the declaration of effectiveness as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
11
Letter to H. Robert Schwall
June 1, 2015
If you have any questions or comments regarding this letter, please contact the undersigned at (215) 832-4130 or Lisa Washington, chief legal officer, at (215) 717-3387.
| Sincerely, |
| /s/ Sean P. McGrath |
| Sean P. McGrath |
| Chief Financial Officer |
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CAWLEY, GILLESPIE & ASSOCIATES, INC.
PETROLEUMCONSULTANTS
| 13640 BRIARWICK DRIVE, SUITE 100 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 625 | ||
| AUSTIN, TEXAS 78729-1707 | FORT WORTH, TEXAS 76102-4987 | HOUSTON, TEXAS 77002-5008 | ||
| 512-249-7000 | 817- 336-2461 | 713-651-9944 | ||
| www.cgaus.com |
June 1, 2015
Mr. Trevor Mallernee
Atlas Resource Partners, LP
1026A Cookson Ave. SE
New Philadelphia, OH 44663
| Re: | Reserve Evaluation | |
| Atlas Resource Partners, LP Interests | ||
| Total Proved Reserves | ||
| Certain Properties in Colorado and Wyoming | ||
| As of December 31, 2014 | ||
| Pursuant to the Guidelines of the | ||
| Securities and Exchange Commission for | ||
| Reporting Corporate Reserves and | ||
| Future Net Revenue | ||
| ||
Dear Mr. Mallernee:
As requested, this report was prepared on June 1, 2015 for Atlas Resource Partners, LP (“Atlas”) for the purpose of submitting our estimates of proved reserves and forecasts of economics attributable to the subject interests. We evaluated 100% of Atlas Rangely Weber Sand Unit Acquisition reserves, which are made up of oil and gas properties in Colorado and Wyoming. It is our understanding that the reserves estimated in this report constituted approximately 12 percent of all reserves owned by Atlas. This report utilized an effective date of December 31, 2014, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). The results of this evaluation are presented in the accompanying tabulation, with a composite summary of the values presented below:
| Proved Developed Producing | Proved Developed Non-Producing | Proved Undeveloped | Total Proved | |||||||||||||||
Net Reserves | ||||||||||||||||||
Oil | – Mbbl | 9,625.9 | 11,977.6 | 5,074.3 | 26,677.9 | |||||||||||||
Gas | – MMcf | 106.2 | 0.0 | 0.0 | 106.2 | |||||||||||||
NGL | – Mbbl | 1,072.3 | 1,211.4 | 339.3 | 2,623.0 | |||||||||||||
Revenue | ||||||||||||||||||
Oil | – M$ | 848,235.6 | 1,055,468.4 | 447,149.0 | 2,350,852.8 | |||||||||||||
Gas | – M$ | 435.3 | 0.0 | 0.0 | 435.3 | |||||||||||||
NGL | – Mbbl | 76,391.7 | 86,303.9 | 24,172.8 | 186,868.5 | |||||||||||||
Severance Taxes | – M$ | 27,751.9 | 34,253.2 | 14,139.7 | 76,144.7 | |||||||||||||
Ad Valorem Taxes | – M$ | 40,398.8 | 49,838.4 | 20,573.2 | 110,810.3 | |||||||||||||
Operating Expenses | – M$ | 391,818.8 | 213,238.5 | 41,043.2 | 646,100.5 | |||||||||||||
Other Deductions | – M$ | 35,547.5 | 7,803.1 | 18,498.3 | 61,848.9 | |||||||||||||
Investments | – M$ | 0.0 | 264,391.7 | 115,194.7 | 379,586.4 | |||||||||||||
Net Operating Income (BFIT) | – M$ | 429,545.8 | 572,247.6 | 261,872.8 | 1,263,666.1 | |||||||||||||
Discounted at 10% | – M$ | 253,633.7 | 62,912.6 | 67,168.6 | 383,715.0 | |||||||||||||
Atlas Resource Partners, LP Interests
Reserve Evaluation
June 1, 2015
Page 2
Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.
The oil reserves include oil and condensate. Oil volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.
Hydrocarbon Pricing
The base SEC oil and gas prices calculated for December 31, 2014 were $94.99/bbl and $4.35/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil and gas prices are based upon WTI-Cushing and Henry Hub spot prices, respectively, as published by the EIA for January 1, 2014 through December 1, 2014.
The base prices shown above were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $88.12 per barrel for oil, $71.24 per barrel of NGL and $4.10 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.
Economic Parameters
Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, ad valorem taxes, severance taxes and lease operating expenses were calculated and prepared by Atlas and were reviewed by us for reasonableness. Capital costs for new development wells, production equipment and workovers were scheduled as provided by Atlas. Capital costs were reviewed by us for reasonableness and compared to capital costs provided in previous years. Adjustments were made as necessary after a review with Atlas. Lease operating expenses were either determined at the field or individual well level using averages calculated from historical lease operating statements. All economic parameters, including lease operating expenses and capital costs, were held constant (not escalated) throughout the life of these properties.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. Government policies and market conditions different from those employed in this report may cause (1) the total quantity of oil or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
Atlas Resource Partners, LP Interests
Reserve Evaluation
June 1, 2015
Page 3
This evaluation includes multiple proved undeveloped locations in the Rangely Weber Sand Unit in Rio Blanco County, Colorado. As requested, estimates of proved undeveloped reserves have only been included for properties that are economically producible at existing economic conditions. Each of these drilling locations proposed as part of Atlas’ development plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, Atlas has indicated they have every intent to complete this development plan within the next five years. Furthermore, Atlas has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five year development plan will be fully executed.
Reserve Estimation Methods
The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.
Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for Atlas properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
General Discussion
An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities havenot been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. (“CG&A”) Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This report has been prepared for Atlas’ use in filing with the Securities and Exchange Commission. This evaluation was supervised by Robert D. Ravnaas, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer
Atlas Resource Partners, LP Interests
Reserve Evaluation
June 1, 2015
Page 4
(License #61304). We do not own an interest in the properties, Atlas Resource Partners, LP and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.
The professional qualifications of the undersigned, the technical person primarily responsible for the preparation of this report, are included as an attachment to this letter.
| Sincerely, | ||
| CAWLEY, GILLESPIE & ASSOCIATES, INC. | ||
| Texas Registered Engineering Firm F-693 | ||
 |  | |
| Robert D. Ravnaas, P.E. | ||
| President | ||
APPENDIX
Explanatory Comments for Summary Tables
HEADINGS
Table I
Description of Table Information
Identity of Interest Evaluated
Property Description – Location
Reserve Classification and Development Status
Effective Date of Evaluation
FORECAST
| (Columns) | ||
| (1) (11) (21) | Calendar orFiscal years/months commencing on effective date. | |
| (2) (3) (4) | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. | |
| (5) (6) (7) | Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. | |
| (8) | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. | |
| (9) | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. | |
| (10) | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. | |
| (12) | Revenue derived from oil sales — column (5) times column (8). | |
| (13) | Revenue derived from gas sales — column (6) times column (9). | |
| (14) | Revenue derived from NGL sales — column (7) times column (10). | |
| (15) | Revenue derived from hedge positions. | |
| (16) | Total Revenue – sum of column (12) through column (15). | |
| (17) | Production-Severance taxes deducted from gross oil, gas and NGL revenue. | |
| (18) | Revenue after taxes – column (16) less column (17). | |
| (19) | Ad Valorem taxes. | |
| (20) | $/BOE6 – is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil. | |
| (22) | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. | |
| (23) | Averagegross wells. | |
| (24) | Averagenet wells are gross wells times working interest. | |
| (25) | Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. | |
| (26) | 3rd Party COPASare combined fixed rate administrative overhead charges for non-operated oil and gas producers. | |
| (27) | Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs. | |
| (28) | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. | |
| (29) (30) | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. | |
| (31) | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. | |
MISCELLANEOUS
| DCF Profile | • | The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns(30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. | ||
| Life | • | The economic life of the appraised property is noted in the lower right-hand corner of the table. | ||
| Footnotes | • | Comments regarding the evaluation may be shown in the lower left-hand footnotes. | ||
| Price Deck | • | A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. | ||
APPENDIX
Methods Employed in the Estimation of Reserves
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports andmay be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.
Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.
Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.
APPENDIX
Reserve Definitions and Classifications
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
“(22)Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“(6)Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
“(31)Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
“(18)Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
“(17)Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant ispermitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
“(26)Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”