*FOIA Confidential Treatment Request*
Confidential Treatment Requested by
Par Pacific Holdings, Inc. (06182018)
June 18, 2018
Via EDGAR and Federal Express
U.S. Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E., Mail Stop 7010
Washington, D.C. 20549
Attention: | Mr. John Reynolds |
Mr. Karl Hiller |
Mr. John Hodgin |
Re: | Par Pacific Holdings, Inc. |
Form 10-K for Fiscal Year Ended December 31, 2017 |
Filed March 12, 2018 |
File No. 001-36550 |
Gentlemen:
This letter is in response to your letter dated May 23, 2018, to Par Pacific Holdings, Inc. (the “Company”), transmitting the comments of the staff (the “Staff”) of the U.S. Securities and Exchange Commission (the “Commission”) relating to the above referenced Annual Report on Form 10-K for the Year Ended December 31, 2017 (the “Form 10-K”). For your convenience, the response is preceded by the Staff’s comment.
Form 10-K for the Fiscal Year ended December 31, 2017
Properties, page 38
Proved Undeveloped Reserves, page 40
1. | We have considered the information provided in your response of March 9, 2018, following our conference calls on February 22, 2018 and March 1, 2018, along with the details included in your response of December 15, 2017, to our prior comments. Based on this |
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information, we do not agree with your conclusion that the volumes you have reported as proved undeveloped reserves as of December 31, 2015 and December 31, 2016 comply with the requirements relevant to reporting such volumes.
Regarding the reporting of proved undeveloped reserves, Rules 4-10(a)(22) and 4-10(a)(31) of Regulation S-X indicate, in relevant part, that a 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” and that undrilled locations may 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.” Compliance and Disclosure Interpretations (C&DI) 131.04 clarifies that “the mere intent to develop, without more, does not constitute “adoption” of a development plan and therefore would not, in and of itself, justify recognition of reserves. Rather, adoption requires a final investment decision.”
Despite these requirements, we note that you have consistently failed to follow the development plans underlying your proved undeveloped reserves and to convert reported proved undeveloped reserves to developed status. The facts and circumstances that you have provided relating to the proved undeveloped reserves disclosed as of December 31, 2015 and 2016, including the successive annual changes in and lack of execution of an adopted development plan and schedule, indicate these do not comply with the requirements for reporting proved undeveloped reserves in Rules 4-10(a)(22) and (a)(31) of Regulation S-X and are inconsistent with the guidance set forth in C&DI 131.04.
Response:
Compliance with Rule 4-10(a)(22) and Rule 4-10(a)(31)
The Piceance Basin can be characterized as a statistically mature Resource Play as such term is defined in the Society of Petroleum Evaluation Engineers Monograph 3. We believe Laramie Energy, LLC’s (“Laramie”) booking of its proved undeveloped (“PUD”) reserves is informed and supported by our interpretation of the Mesaverde Formation across our acreage block as a consistent, predictable reservoir. We believe this interpretation is appropriate based upon our analysis of drilling results within the Piceance Basin. The Piceance Basin encompasses over 2.5 million productive acres, with over 12,000 wells drilled to date. The Southern half of the Piceance Basin is highly developed in the primary target, the Mesaverde, with numerous published papers on geologic structure, faulting, hydrocarbon sourcing, and rock geo-mechanics drawing from an extensive database of well penetrations, whole cores, open-hole logs, cased hole logs, conventional seismic, and micro-seismic surveys. The bulk of the Southern portion of the Piceance Basin, where Laramie operates and most industry development has occurred, was spaced on 10-acre density (one well per 10 acres) through the Colorado Oil & Gas Conservation Commission, which spacing was set after extensive geologic and engineering testimony. Reserves are easily
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calculated using standard volumetric analyses, with a typical recovery factor of +70% of original gas in place. We further believe this interpretation is appropriate based upon our analysis of drilling results within the Piceance Basin. Laramie has drilled more than 200 economically successful wells since 2012. In recognition of these drilling and production dynamics, Laramie, like many other resource play operators in the Piceance Basin, utilizes directional pad drilling techniques on a section by section basis to develop its PUD reserves. See Exhibit A attached here for an illustration of pad drilling.
In addition to such directional pad drilling techniques, due to the emergence and further refinement of certain technological innovations in completion techniques, such as low-cost proppantless fracturing, or “sandless fracing,” as discussed below, operators such as Laramie have utilized enhanced frac design to reduce the overall number of wells required to drain the same proven undeveloped acreage. As a result of these larger fracs, Laramie observed that wells were draining more acres per well. Accordingly, Laramie adjusted its development well pattern from four to three column spacing per section in 2016 and from three to two column spacing per section in 2017 to account for these improvements, as discussed below. See Appendix A, which is being furnished to the Staff under separate cover pursuant to Rule 12b-4 under the Securities Exchange Act of 1934, as amended, and under the Freedom of Information Act and is not being filed electronically as part of this letter, for an illustration depicting this change in Laramie’s drilling pattern. The intent of these new drilling patterns is to more efficiently develop the same sections, acreage and reserves as were targeted in prior development plans with fewer wells. Laramie, as well as other operators in the field, have evolved their drilling and completion techniques similar to the way operators in the Permian Basin, Williston Basin and other areas have changed their spacing and completion strategy to utilize longer drilling laterals (instead of two shorter laterals) to more efficiently drain the same resource area.
Based on our analysis of the Piceance Basin and our ability to target the same underground resources utilizing fewer wellbores, we believe that the proved undeveloped reserve estimates we reported for the years ended December 31, 2015, 2016 and 2017, which were independently estimated by Netherland, Sewell & Associates, Inc., were estimated with reasonable certainty to be economically producible in compliance with Rule 4-10(a)(22) of Regulation S-X. Additionally, as discussed below, based on Laramie’s acreage position, contractual drilling obligations, well economics, and development plans at the time the reserves were classified as proved, we believe that the classification of proved undeveloped reserves in our reserve reports as of December 31, 2015, 2016 and 2017 was appropriate and complied with Rule 4-10(a)(31) of Regulation S-X and C&DI 131.04.
Changes in the Development Plans
While the Staff cites to changes in and lack of execution of our adopted development plans as evidence of our failure to satisfy Rules 4-10(a)(22) and 4-10(a)(31) of Regulation S-X and C&DI 131.04, we believe that based on our prior discussions with the Staff that changes
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in development plans are permissible under certain circumstances. Provided below is a detailed explanation of our development plans relating to the proved undeveloped reserves included in our reserve reports as of December 31, 2015, December 31, 2016 and December 31, 2017 and the factors that were evaluated leading to the conclusion that such reserves satisfy such requirements. In addition, we provide a detailed description of the exogenous factors that lead to what we believe are permissible changes to our development plans, which plans included the weighting of completions in later years. This has been confirmed by our performance to date in 2018 with respect to the conversion of our year-end 2017 proved undeveloped reserves, of which 25% of aggregate PUD reserves in our year-end 2017 reserve report have been developed to date, with 50% of aggregate PUD reserves in our year-end 2017 reserve report projected to be developed by year end 2018. Pursuant to the Staff’s request, Exhibit B attached hereto is a timeline setting forth the occurrence of these events and factors.
Year End 2015 Reserve Report
At year-end 2015, Laramie adopted its development plan based upon the prevailing commodity price environment, existing acreage position, extant gathering and processing arrangements and well economics. A summary of the 2015 year-end development plan broken out by year is depicted in the below table1:
2016 | 2017 | 2018 | 2019 | 2020 | Total | |||||||||||||||||||
Gross Wells | 0 | 30 | 98 | 17 | 2 | 147 | ||||||||||||||||||
Net Bcfe to Par | 0 | 19.6 | 44.9 | 9.1 | 1.1 | 74.7 |
2015 Year-End Development Plan Material Facts:
At the time Laramie adopted the 2015 year-end development plan, the Colorado Interstate Gas (“CIG”) December 2014 average price was $1.86/MMBtu. Sustained prices at this level would have materially reduced the rates of return on Laramie’s locations in the Piceance Basin. However the 60-month forward CIG strip price was $2.60/MMBtu. In its 2015 year-end development plan, Laramie planned for minimal activity during 2016 and instead planned to complete the construction of a $17.6 million water handling, treatment, processing and storage facility. Laramie improved its infrastructure capacity in anticipation
1 | As previously disclosed to the Staff and reflected in our December 15, 2017 and March 9, 2018 response letters, the development plan has been adjusted to show only wells that are completed in any given year of the plan and to reflect the removal of PUDs scheduled to be developed more than five years from initial booking as reflected in Note 23 to the financial statements in our Annual Report on Form 10-K for the year ended December 31, 2017. |
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of future development utilizing sandless fracing, with significantly higher water volumes, as discussed below, by constructing a 15,000 barrel per day water treatment facility and two 500,000 barrel lined storage ponds for recycling flow-back water. Upon completion, the water treatment facility was expected to allow Laramie to more efficiently transport water in greater quantities via pipeline to its drilling pad locations (as opposed to more expensive and less efficient truck delivery) reducing the drilling and completion costs by an estimated 25% per well. At the time Laramie adopted its year-end 2015 development plan, management expected the water handling facility would be fully permitted and operational by March 2016 allowing for improved rates of return on future drilled and completed PUD locations between 2017-2020. This significant capital investment in improved infrastructure provided additional certainty, at the time the year-end 2015 development plan was adopted, with respect to Laramie’s plan to develop proved undeveloped locations more economically between 2017-2020. In summary, the investment in and operation of the water handling infrastructure was integral to the planned development in 2017–2020 and drove the expectation that approximately 72% of total PUD reserves would be converted in year 3 and year 4 (2018 and 2019) of the development plan.
2016 Material Events:
At the end of 2015 and over the course of 2016, several exogenous events occurred that would lead to changes in the 2015 year-end development plan. Most notably, in December 2015, Laramie entered into a purchase and sale agreement with respect to a significant acquisition of oil and gas assets from Occidental Petroleum Corporation (“Occidental”), which closed in March 2016. The Occidental assets acquired were not included in Laramie’s 2015 year-end development plan because the acquisition was not consummated at year-end 2015 and due to the uncertainty with respect to the consummation of the acquisition based upon, among other things, the existence of multiple closing conditions. The size of the acquisition was more akin to a business combination, with Laramie’s net leasehold and mineral acreage doubling from approximately 54,000 to 108,000, surface acreage increasing from 7,000 to 27,000, and operated wells increasing from 360 to 1,200. In addition, Laramie’s proved developed reserves increased by almost three times and its proved undeveloped locations increased by 140%. The integration of these acquired assets also was a factor in Laramie’s decision to defer development drilling in the first half of 2016. [****]. Due to this contractual obligation, Laramie modified its development plans in future years to include these newly acquired wells.
In addition, the water handling facility commenced operations in July 2016, instead of March 2016, due to a permit delay. Furthermore, between May 2016 and September 2016, Laramie completed six proved developed non-producing wells testing a new completion design, with favorable results. Utilizing sandless fracs with increased water volume, Laramie reduced costs by an estimated 15% per well. This sandless completion design has allowed operators such as Laramie to pump larger frac jobs, while reducing the overall number of wells required to drain proven undeveloped acreage. This caused Laramie to
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adjust its development well pattern to utilize these technological innovations and corresponding changes in spacing, with a shift from a four to three column spacing per section. Using these larger fracs resulted in increasing recoveries of gas in place. A four column drilling pattern comprises the location of four columns across a given section, with 16 rows and 64 wells drilled from four drilling pads (or 16 wells per pad) on such section along the four columns. Conversely, a three column spacing per section drilling pattern reduces the number of drilling pads and columns from four to three, and increases the number of rows from 16 to 21 per pad. See Appendix A for an illustration depicting this change in Laramie’s drilling pattern. As a result of this switch to a three column drilling pattern, certain bottomhole locations, well names and well counts changed, but the sections, acreage and reserves targeted by Laramie’s drilling program remained the same. The combination of the sandless completion design, increased water volumes and the water infrastructure plant reduced drilling and completion costs by an estimated 25% per well. These material cost reductions driven by planned capital deployment into water handling infrastructure, technical innovation of completion design and an evolving drilling pattern would materially impact the planning process in establishing the 2016 year end development plan.
Year End 2016 Reserve Report
At year-end 2016, Laramie adopted its development plan based upon the prevailing commodity price environment, existing acreage position, extant contractual drilling obligations, gathering and processing arrangements, and well economics. A summary of the 2016 year-end development plan broken out by year is depicted in the below table2:
2017 | 2018 | 2019 | 2020 | 2021 | Total | |||||||||||||||||||
Gross Wells | 31 | 71 | 128 | 52 | 0 | 282 | ||||||||||||||||||
Net Bcfe to Par | 19.1 | 42.7 | 85.5 | 30.9 | 0 | 178.2 |
2016 Year-End Development Plan Material Facts and Comparison to 2015 Year-End Development Plan:
At the time Laramie adopted the 2016 year-end development plan, the CIG December 2015 average price was $3.42/MMBtu and the 60-month forward CIG strip price was
2 | As previously disclosed to the Staff and reflected in our December 15, 2017 and March 9, 2018 response letters, the development plan has been adjusted to show only wells that are completed in any given year of the plan and to reflect the removal of PUDs scheduled to be developed more than five years from initial booking as reflected in Note 23 to the financial statements in our Annual Report on Form 10-K for the year ended December 31, 2017. |
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$2.66/MMBtu. Within its 2016 year-end development plan Laramie planned for the majority of activity to occur within years 2 and 3 (2018 and 2019), where an estimated 72% of conversion activity was projected by volume.
The material changes in Laramie’s development plan and the changes in its reserves reports from year-end 2015 to year-end 2016 can be accounted for based principally on the Occidental acquisition and related contractual minimum volume commitments, completion technique improvements, the completion of the water treatment facility, and the shift from a four column to three column per section drilling pattern. [****]. In addition, Laramie added 39 locations and 29.6 Bcfe within acreage acquired from Occidental. In total, these new locations and reserves represented 23% and 26% of 2016 year-end locations and reserves, respectively. PUD volumes also were increased at year-end 2016 with respect to the locations closest in proximity to the newly constructed water treatment facility due to improved economics resulting from Laramie’s ability to pipe water to drilling pad locations, increasing well counts and reserves in these locations by 5 and 11.9 Bcfe, respectively. Laramie also increased the number of proved undeveloped reserves by 91 locations and 57.7 Bcfe due to improved rates of return compared to the year-end 2015 development plan resulting from the material drilling and completion cost reductions and changes in completion techniques, each as described above. 27 PUD locations representing 11.7 Bcfe of reserves were removed due to lower relative rates of return to other PUD locations, resulting in rescheduling development outside of the five-year development plan. In aggregate, 135 locations and 103.5 Bcfe were added in the year-end 2016 development plan based upon the events described above.
Excluding the effect of the reserves acquired in the Occidental acquisition, 65% of PUD volumes at year-end 2016 came from sections that also carried PUD reserves at year-end 2015. While the well locations may have changed to some degree, Laramie targeted the same resource with these identified PUD locations. See Appendix B, which is being furnished to the Staff under separate cover pursuant to Rule 12b-4 under the Securities Exchange Act of 1934, as amended, and under the Freedom of Information Act and is not being filed electronically as part of this letter, for an illustration setting forth these PUD carryforwards by section.
2017 Material Events:
During the course of 2017, certain external events occurred that would lead to changes in the 2016 year-end development plan. In January 2017, Laramie finalized its renegotiation of a key gathering and processing contract with Enterprise Gas Processing LLC (“Enterprise”), [****]. Laramie adjusted its development plan following the Enterprise contract renegotiation in order to capture the benefits of the improved gathering and processing contract. [****]. The magnitude of this benefit would require Laramie to reevaluate its development plan. [****]. Laramie therefore modified its development plan
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in the spring of 2017 and drilled and completed certain probable locations during 2017 to ensure it captured the material benefit from the new contract.
In July 2017, while preparing proved undeveloped reserve locations it added to its development plan to satisfy the Occidental drilling commitment, Laramie observed significant cracks, ranging from two to six inches in size, in one of its pad sites. Such cracking caused this pad to slump towards another pad site within the same section, which was located downhill from damaged pad site. As a result of this pad failure, Laramie deferred drilling operations on these two sites in order to repair the malfunctioning well pad. This pad failure resulted in the rescheduling of the drilling of 27 proved undeveloped locations included in its 2016 development plan from 2017 to 2018. The damaged pad was repaired, drilling commenced in late 2017 on both pads, and the wells were subsequently completed in early 2018.
In total, Laramie converted 34 proved undeveloped wells to developed status during 2017 representing a conversion ratio of 13%. Of these 34 wells, 9 were scheduled for completion in 2017 and the remaining 26 were accelerated. [****].
Year End 2017 Reserve Report
At year-end 2017, Laramie adopted its development plan based upon the prevailing commodity price environment, existing acreage position, extant contractual drilling obligations and gathering and processing arrangements, and well economics. As previously disclosed to the Staff, Par adopted a two year drilling and three year completion plan, based on Laramie’s plan. A summary of our 2017 year-end development plan broken out by year is depicted in the below table:
2018 | 2019 | 2020 | 2020 | 2021 | Total | |||||||||||||||||||
Gross Wells | 122 | 60 | 39 | 0 | 0 | 221 | ||||||||||||||||||
Net Bcfe to Par | 68.9 | 41.8 | 28.1 | 0 | 0 | 138.8 |
2017 Year-End Development Plan Material Facts and Comparison to 2016 Year-End Development Plan:
At the time of the adoption of the 2017 year-end development plan, the CIG December 2016 average price was $2.48/MMBtu and the 60-month forward CIG strip price was $2.36/MMBtu. The 2017 year-end development plan planned for the majority of activity to occur within years 1 and 2 (2018 and 2019), where an estimated 80% of conversion activity was projected by volume.
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The changes in the development plan and the changes in the reserves reports from year-end 2016 to year-end 2017 can be accounted for based on the factors discussed above, particularly the additional contractual drilling obligations (and economic incentive) contained in the renegotiated Enterprise agreement. In addition, Laramie shifted to a two column spacing per section development pattern across all remaining undeveloped acreage to further reduce required wells to efficiently develop its undeveloped reserves and enhance economic realizations. 34 locations, representing 24.9 Bcfe, were converted to proved developed producing. [****]. A net 6 PUD locations and 8.9 Bcfe were added to the year-end 2017 development plan in connection with Laramie’s shift to two column spacing in the acreage acquired from Occidental. 40 PUD locations and 22.5 Bcfe were added to the year-end 2017 development plan that were (i) drilled but not completed as of such time and (ii) previously categorized as probable reserves. 45 PUDs and 28.5 Bcfe were added due to higher rates of return because of their proximity to the water treatment facility. Conversely, 27 PUD locations and 15.1 Bcfe were dropped due to their distance from the water treatment facility. One PUD location and .6 Bcfe were added after new acreage was leased requiring one well to hold the leasehold by production. An additional 124 locations, representing 71.8 Bcfe of reserves were dropped at year-end 2017 in favor of other locations due to their proximity to infrastructure and ability to satisfy contractual obligations in the Enterprise agreement. In aggregate, PUDs were decreased by 61 and 39.4 Bcfe in the year-end 2017 development plan compared to 2016.
While there are several movements occurring compared to 2016, consistent with the shift in approach to pad drilling and the targeting of sections in a resource play, 73% of the PUD volumes at year-end 2017 come from sections that also carried PUD reserves at year-end 2016. See Appendix B for an illustration setting forth these PUD carryforwards by section.
2018 Year to Date Material Events:
Performance to date in 2018 has been consistent with the 2017 year-end plan. To date in 2018, 25% of aggregate PUD reserves in our year-end 2017 reserve report have been developed, with 50% of aggregate PUD reserves in our year-end 2017 reserve report projected to be developed by year end 2018.
Conclusion:
In summary, we believe that the classification of proved undeveloped reserves in our reserve reports as of December 31, 2015, December 31, 2016 and December 31, 2017 was appropriate and complied with Rules 4-10(a)(22) and 4-10(a)(31) of Regulation S-X and C&DI 131.04 . Based on our prior discussions with the Staff we believe that changes in development plans are permissible under certain circumstances. Laramie’s deviations from
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its year-end 2015 and year-end 2016 development plans were related to several external factors, particularly its entry into the Occidental acquisition, its renegotiation of its primary processing contracts and its utilization of technological innovations in completion techniques and changed well spacing and directional drilling geometries resulting from the switch, ultimately, to two column drilling.
Laramie, like most other operators in the Piceance Basin, utilizes pad drilling techniques on a section by section basis to develop its PUD reserves. Accordingly, while individual bottomhole locations, well names and well counts changed, the sections, acreage and reserves targeted by Laramie’s drilling program remained the same. For example, 73% of the PUD volumes at year-end 2017 come from sections that also carried PUD reserves at year-end 2016.
At year-end 2017, we adopted a more conservative, front-end weighted, three year development plan in order to increase our reasonable certainty. To date, Laramie has developed 25% of aggregate PUD reserves in the year-end 2017 reserve report, with 50% of aggregate PUD reserves projected in the year-end 2017 reserve report to be developed by year end 2018. We believe that this performance evidences our reasonable certainty with respect to the year-end 2017 development plan.
2. | In connection with your determination of proved undeveloped reserves as of December 31, 2017 we note that you limited the timeframe for future development, although you have not described any factors that would support an assertion of reasonable certainty with respect to the three-year timeframe that you have utilized. We also note that you formed a reserve committee which you state will “ensure PUDs are developed in accordance with the annual reserve report and related development plan.” However, you have not described any specific changes in the manner by which locations were scheduled for development in preparing the December 31, 2017 reserve estimates, nor any specific change in the level of your influence over development activities, as a result of this committee, that would support an assertion of reasonable certainty with respect to the future development of the identified locations as scheduled. |
Based on the information that you have provided, we do not see adequate support for an assertion of reasonable certainty with respect to the development plans underlying your estimates of proved undeveloped reserves as of December 31, 2017. Accordingly, we believe these reserves do not comply with the requirements for reporting proved undeveloped reserves in Rules 4-10(a)(22) and (a)(31) of Regulation S-X, and are inconsistent with the guidance set forth in C&DI 131.04. If you believe there is additional information that supports and clarifies your perspective, that is responsive to these concerns, clarify this for us and address the following points.
• | Explain how the use of a two year drilling and three year completion time horizon provides reasonable certainty that locations will be developed in accordance with the development plan and schedule adopted as of December 31, 2017, considering your consistent failure to convert reserves during this interval in prior development plans; |
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Response: The shorter time horizon provided by the two year drilling and three year completion development plan generally increases our reasonable certainty with respect to this development plan. To this end, PUDs are front-end loaded within the three year completion time horizon, as we believe that these earlier years are even more predictable than the later years. We respectfully submit to the Staff that the prior year development plans have generally required the majority of development in years 2018 and 2019 of the plans. The objective of shortening the development timeline and more notably scheduling approximately 50% of the reserves by volume in year one is to address Laramie’s historically low conversion rates and to reduce the impact of commodity price volatility. The processes outlined below with respect to the formation and reconciliation activities of the representatives of the reserves committee also evidences for the reasonable certainty of the plan.
A number of factors provide support for our reasonable certainty with respect to the three-year timeframe that we have utilized. [****]. Additionally, 57 proved undeveloped wells were drilled but uncompleted as of December 31, 2017, resulting in substantially less capital required for conversion to PUDs over the course of 2018. Laramie has sufficient capital to fund its drilling operations under its revolving credit facility, and is over 90% hedged on its existing production through December 2018.
Most importantly, Laramie’s actual drilling performance to date in 2018 evidences our reasonable certainty with respect to the development plan. To date in 2018, 25% of aggregate PUD reserves in our year-end 2017 reserve report have been developed, with 50% of aggregate PUD reserves in our year-end 2017 reserve report projected to be developed by year end 2018. In summary, the combination of Laramie’s adequate capital resources, existing contractual drilling commitments and performance to date in 2018 with respect to the conversion of PUDs, support our assertion of reasonable certainty with respect to our year-end 2017 development plan.
We additionally inform the Staff that there have been no material deviations in 2018 with respect to our year-end 2017 development plan, with only three PUDs being deferred and six being advanced, out of a total of 122 PUD locations planned in the year-end 2017 development plan.
• | Explain why all of the previously disclosed proved undeveloped locations were removed and substituted with new locations in the reserves report as of December 31, 2017; and how a change of this magnitude is consistent with having final investment decisions for specific locations; |
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Response: We respectfully inform the Staff that we do not view these removals of proved and undeveloped locations in the reserves report as of December 31, 2017 as being inconsistent with having final investment decisions for these specific locations, as the substituted drilling locations substantially overlap with the removed locations. The naming convention of these locations was changed based upon technological advancements in drilling and completion techniques as well as updated well geometries, with the result that the same general areas are being exploited, with 73% of the PUD volumes at year-end 2017 coming from sections that also carried PUD reserves at year-end 2016. As previously described, Laramie utilizes pad drilling techniques, with multiple wells drilled from a single pad. The number of wells in a section (640 acres/1 sq. mile) has been reduced from 63 to 42 commencing in the latter part of 2017 and continuing into 2018 due to the evolution of large volume sandless fracing and the resulting changes from a three column to a two column spacing per section development well pattern with two drilling pads per section comprising 21 wells per pad, as opposed to three pads. As previously discussed, changes in technology have allowed each well to drain more acreage. This reduction in the number of wells has resulted in certain removals and substitutions of locations by name, but as discussed above, it has not resulted in a change in the targeted sections, acreage or reserves. The intent of the new spacing and completion combination in the year-end 2017 development plan is to efficiently develop the same sections, acreage and reserves as the original development plan – drilling 42 wells per section with 15 acre-spacing per well instead of 63 wells per section at 10 acres per well. See Appendix A for an illustration depicting the change in drilling patterns.
• | Explain how the formation of a reserves committee provides reasonable certainty over adherence to the development plans and the schedules underlying the annual reserve report; describe the composition of the committee and any specific actions they have taken with respect to the December 31, 2017 development plan and subsequent activities that differ from your historical practices; |
Response: We respectfully inform the Staff that the reserves committee is an enhancement of our existing processes with respect to the determination of reserves and with respect to our influence over Laramie’s development activities.
We believe that the following factors demonstrate our access to sufficiently detailed information about, and our corresponding ability to influence Laramie, with respect to development activities. Pursuant to Section 5.1 of the Third Amended and Restated Limited Liability Company Agreement of Laramie (the “Laramie LLC Agreement”), which is filed as Exhibit 10.2 to our Annual Report on Form 10-K for the year ended December 31, 2017, we have the right to appoint two of the six members of the board of Laramie. We have appointed our Chief Executive Officer and our Chief Financial Officer to the Laramie board. Pursuant to Section 5.3 of the Laramie LLC Agreement, quarterly budgets and quarterly capital expenditures
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in excess of $1,000,000 are required to be approved in person at a Laramie board meeting. Pursuant to Section 9.10 of the Laramie LLC Agreement, Laramie is required to provide monthly reports with respect to drilling and completion activities, as well as a comparison of budgeted versus actual amounts spent to its members, including us. Additional reporting is also required of Laramie on a quarterly and annual basis (including audited annual financial statements and a third party reserve engineering report), including review and approval of a drilling plan. Laramie and the Company each use the same accounting firm, though each has different audit teams, and the same reserve engineering firm and engineering staff.
While we do not control Laramie, an entity in which we own 39.1% of the outstanding equity interests, the factors set forth above, when considered as a whole, provide us with detailed information regarding Laramie’s development activities, which detailed information is reviewed by our reserves committee to determine whether any feedback should be given to Laramie. Such feedback may be given through the board of Laramie, as a result of our appointment of members of the Laramie board, though we have always maintained open lines of communication directly with Laramie’s management. As an example, we have shared the Staff’s comments with Laramie’s management and they have actively participated in our process of evaluating and responding to each of the comments.
Each of these factors discussed above are not new, but have been in place in Laramie’s current LLC agreement and the prior versions thereof and the reserves committee was formed as an enhancement of these existing processes. Specifically, the reserves committee is tasked with utilizing the information that we have been receiving from Laramie in order to provide necessary feedback to Laramie with respect to its development activities and its determination of reserves in accordance with the Staff’s guidelines.
Our reserves committee is currently comprised of the following members: our Chief Executive Officer; our Chief Financial Officer; our General Counsel and Secretary; our Chief Accounting Officer; our Associate General Counsel; our Director of Financial Reporting; an M&A analyst with a background in the oil and gas industry; and representatives from our independent reserve engineering firm. Representatives from our reserves committee communicated regularly with Laramie’s management and their reserve engineers in connection with the creation and development of the year-end 2017 development plan. In that regard, such representatives performed detailed reconciliations of the proposed development plan, drilling schedule and financial models.
• | Explain how the identification of individual drill sites/wells was considered in connection with the development of your estimate of proved undeveloped reserves as of December 31, 2017 and how this consideration compared to estimates of proved undeveloped reserves as of December 31, 2015 and December 31, 2016; and, |
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Page 14 | Par Pacific Holdings, Inc. (06182018) |
Response: We identified drilling locations in connection with the development of our estimate of proved undeveloped reserves as of year-end 2017 with consideration for the results obtained from development activities in prior years, the material cost reductions achieved through 2016 and 2017, the acreage subject to Laramie’s contractual commitments to Enterprise and as a result of the Occidental acquisition, the proposed locations’ proximity to water handling infrastructures and drilling locations reflected in prior development plans. We removed certain locations that were included in the prior year’s development plan due to less favorable economics, including the costs required to access existing water handling infrastructure compared to other locations. Conversely, we added certain locations that were proximate to such infrastructure. The various factors occurring in 2016 and 2017 discussed above were also considered in connection with the identification of individual drill sites/wells and the development of our proved undeveloped reserves as of December 31, 2017, 2016 and 2015. As discussed above, the emergence of low-cost sandless fracing was a factor considered in estimating proved undeveloped reserves in these periods, as such development changed drilling activity to account for the increased frac sizes, with their resultant well decreases necessary to drain proven undeveloped acreage. Laramie adjusted its development well pattern accordingly. While the targeted sections, acreage and reserves to be developed remained the same, the surface and bottomhole locations have changed from 2015 to present. See Appendix B for an illustration setting forth these PUD carryforwards by section. Each year-end reserve report during that period of time and the associated development plan with respect to each such reserve report reflects the latest development well pattern (whether four column, three column or two column). See Appendix A for an illustration depicting the change in drilling patterns.
• | Explain how the development schedule underlying your proved undeveloped reserves as of December 31, 2017, including the identification and timing of specific sites/wells, compares to the development schedule of the operator. |
Response: Our two year drilling and three year completion development schedule as of December 31, 2017 is identical to Laramie’s development schedule as of December 31, 2017 (for the same time period in 2018, 2019 and 2020) with respect to the PUDs included in our year-end 2017 reserve report, other than our elimination of 4 wells in 2018, and 11 wells in 2019 because the scheduled completion dates for such wells were approaching the fourth year of the 5-year development window at the time the plan was developed.
We respectfully submit that conclusions regarding reasonable certainty of development of PUDs can differ between those conclusions drawn by management of an equity method investee and those of management of its minority investor, much
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like a non-operator may take a more conservative position than an operator may take with respect to certainty of a development plan. For management of Par Pacific, this conclusion was reached with respect to the outlying years of development.
Please call the undersigned at (832) 916-3386 with any additional comments or questions you may have.
Very truly yours, |
/s/ J. Matthew Vaughn |
J. Matthew Vaughn |
Senior Vice President and General Counsel |
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Par Pacific Holdings, Inc. (06182018) |
Exhibit A
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Exhibit B
LARAMIE ENERGY, LLC
Laramie Development Plan Timeline (2015-2018)
Year | Month | Event | Natural Gas Price (WRH)* | |||||
2015 | 9 | Laramie is impacted by water access and permitting delays related to its construction of a critical water treatment facility. | $2.51 | |||||
12 | Laramie’s Board meets and approves a material acquisition of assets from Occidental Petroleum Corporation (“Occidental”), subject to multiple closing conditions. If consummated, the Occidental acquisition will increase Laramie’s PUDs locations by 140%. Laramie would also be required to drill 60 wells in certain Occidental acreage by January 2018 or Laramie would be required to pay significant financial penalties.
|
| $1.95
|
| ||||
2 | Laramie receives its year-end 2015 reserve report from its independent reserves engineer. Only 162 proved undeveloped reserves (“PUDs) are economic at Securities Exchange Commission (“SEC”) pricing. The report reflects 4-column drilling. | $1.75 | ||||||
3 | Laramie closes the Occidental acquisition. Laramie’s Board meets shortly thereafter and adopts a revised development plan that prioritizes development of reserves in certain Occidental acreage. Laramie’s Board is concerned about very low natural gas prices. | $1.50 | ||||||
6 | Laramie successfully tests a 3-column drilling design. Laramie’s Board approves a switch from 4-column to 3-column drilling. As a result of this switch to a 3-column drilling patern, certain bottomhole locations, well names and well counts changed, but the sections, acreage and reserves targeted by Laramie’s drilling program remained the same. | $2.32 | ||||||
7 | Laramie’s water treatment facility becomes operational. | $2.54 | ||||||
9 | Laramie’s Board approves testing of 2-column drilling.
|
| $2.69
|
| ||||
2017 | 1 | Laramie signs the Enterprise contract, resulting in improved well economics but also obligating Laramie to drill at least 150 wells on certain specified acreage. | $3.17 | |||||
2 | Laramie receives its year-end 2016 SEC reserve report from its independent reserves engineer. 316 PUDs are economic at SEC pricing. The report reflects 3-column drilling. | $2.58 | ||||||
7 | A pad failure causes the development of 27 PUDs to be rescheduled from 2017 to 2018. | $2.60 | ||||||
10 | Laramie’s Board approves a switch from 3-column to 2-column drilling. As a result of this switch to a 2-column drilling patern, certain bottomhole locations, well names and well counts changed, but the sections, acreage and reserves targeted by Laramie’s drilling program remained the same. | $2.67 | ||||||
12 | Par reduces the time horizon for PUDs development to two-years for drilling and three years for completions.
|
| $2.50
|
| ||||
2018 | 2 | Par receives its year-end 2017 SEC reserve report from its independent reserves engineer based on its more conservative development plan. 221 PUDs are economic at SEC pricing. The report reflects 2-column drilling. | $2.29 | |||||
2 | The damaged pad is repaired and the wells on the pad are drilled and completed. | $2.29 | ||||||
6 | To date, Laramie has drilled and completed approximately 27% of its year-end 2017 PUDs, and projects that over 55% of such PUDs will be drilled at completed by the end of 2018. |
* | WRH - White River Hub average of gas daily prices during the referenced month. |
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Appendix A
Furnished to the Staff under separate cover pursuant to Rule 12b-4 under the Securities Exchange Act of 1934, as amended, and under the Freedom of Information Act.
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Par Pacific Holdings, Inc. (06182018) |
Appendix B
Furnished to the Staff under separate cover pursuant to Rule 12b-4 under the Securities Exchange Act of 1934, as amended, and under the Freedom of Information Act.