Vanguard Natural Resources, LLC
5487 San Felipe, Suite 3000
Houston, Texas 77057
August 11, 2015
VIA EDGAR
U.S. Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, DC 20549
Attention: H. Roger Schwall, Assistant Director
Ethan Horowitz, Branch Chief
Wei Lu, Staff Accountant
Parhaum J. Hamidi, Staff Attorney
Norman von Holtzendorff, Senior Counsel
Ronald Winfrey, Petroleum Engineer
| |
| Re: | Vanguard Natural Resources, LLC
Amendment No. 2 to Registration Statement on Form S-4 |
Filed July 24, 2015
File No. 333-204696
Form 10-K for Fiscal Year Ended December 31, 2014
Response Dated July 24, 2015
File No. 1-33756
Dear Mr. Schwall:
This supplemental response letter is being submitted by Vanguard Natural Resources, LLC, a Delaware limited liability company (the “Company”, “Vanguard”, “We”, “Us” or “Our”), to the Securities and Exchange Commission (the “Commission”) as a follow up to our response letter, dated August 6, 2015 (the “Response Letter”), which set forth our responses, other than to comment number 2, to the comment letter from the staff (the “Staff”) of the Division of Corporation Finance of the Commission, dated July 31, 2015 (the “Comment Letter”), relating to the Company’s Registration Statement on Form S-4 (File No. 333-204696) (the “LRE/Vanguard Form S-4”), which was filed with the Commission on June 3, 2015, as amended by Amendment No. 2 to the LRE/Vanguard Form S-4 (“LRE/Vanguard Amendment No. 2”), which was filed with the Commission on July 24, 2015, and the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014 (the “Vanguard Form 10-K”), which was filed with the Commission on March 2, 2015. On August 6, 2015, concurrently with the submission of the Response Letter, we filed Amendment No. 3 to the LRE/Vanguard Form S-4 (“LRE/Vanguard Amendment No. 3”) and Amendment No. 3 (“EROC/Vanguard Amendment No. 3”) to the Company’s Registration Statement on Form S-4 (File No. 333-204982), which was filed with the Commission on June 16, 2015.
In the Response Letter, we stated that we would subsequently file this supplemental response letter to outline our response to comment number 2 of the Comment Letter and to provide certain additional data related to our development plans for prior years. Our response to comment number 2 of the Comment Letter can be found below.
In this letter, for your convenience, we have recited comment number 2 of the Comment Letter in italicized, bold type and have followed such comment with the Company’s response.
U.S. Securities and Exchange Commission
August 11, 2015
Page 2
Based on our review of the Comment Letter, and as further described herein, we believe that the Vanguard Form 10-K is materially accurate and, accordingly, that amendment is not necessary.
Form 10-K for Fiscal Year Ended December 31, 2014
Oil, Natural Gas and NGLs Data, page 8
Proved Undeveloped Reserves, page 11
| |
| 2. | In response to prior comment 3, you state, “The formula we used to calculate our PUD conversion ratio is as follows: Conversion Fraction = (PUDs drilled + PUDs dropped) / (Prior Year PUD reserve balance)…As such, taking 2013 PUDs converted during 2014 alone into consideration, as shown in the calculation above, does not represent our historical conversion rate since the capital that was scheduled to be spent on 2013 PUDs was spent on PUDs added during 2014.” It is the staff’s view position that PUD volumes “dropped” from the reserves portfolio are not equivalent to PUD volumes converted to developed status. In the last five years (fiscal 2010-2014), the cumulative conversions of the PUD reserves which you have disclosed appear to total about 28.5% of the PUD reserves available for drilling at the beginning of each period. For the last three fiscal years , the cumulative conversions appear to be about 14% of the PUD reserves available at the beginning of each year with the largest year’s conversion at 9% for 2014. Your dropped PUD volumes over the last three years appear to be about 182.9 BCFE while the converted volumes appear to be about 28.6 BCFE. The annual conversion rates underlying these cumulative conversion amounts are substantially below the annual conversion rates implied by the five year limitation on PUD reserves. The definitions provided in paragraphs 22 and 31 of Rule 4-10(a) of Regulation S-X indicate that it is only appropriate to claim proved undeveloped reserves if it is reasonably certain that the project to develop the reserves will commence within five years, unless specific circumstances justify a longer time. Compliance and Disclosure Interpretation 131.04 further 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. Given the definitions and interpretations applicable to proved undeveloped reserves, and that you have not developed your reserves according to the plans underlying your disclosed reserve estimates, we believe you should revise your reported reserve volumes and the internal controls used in your reserve estimation process to limit disclosed proved undeveloped reserve volumes to those quantities which are reasonably certain to be developed within five years of initial booking. |
Response:
We acknowledge the Staff’s comment. As disclosed in the prior response letters to the Staff’s comments, we believe our development plan is in compliance with the requirements of Rule 4-10(a)(31)(ii) of Regulation S-X. Any historical short-fall between PUDs scheduled to be drilled and actual drilling and conversion of PUD volumes to PDP volumes is not indicative of a lack of the requisite reasonable certainty regarding the projected development of reserves during any prior year. Management has been focused on improving historical conversion rates and we have been successful with these efforts. Our projected conversion ratio for the year ending December 31, 2015 is approximately 15.6%. During the first seven months of 2015 we have converted approximately 7.0% of our 2014 proved undeveloped reserves ("PUDs"). As of July 31, 2015, we have spent approximately $31.6 million of our $105.7 million planned budget for conversion of PUD volumes
U.S. Securities and Exchange Commission
August 11, 2015
Page 3
and have converted 47.3 Bcfe of PUD volumes out of the planned 101.9 Bcfe. Additionally, during 2015, we have spent approximately $7.3 million on work in progress drilling wells that are not yet completed. Through 2015, we have benefited from reduced service costs, which, combined with increased drilling efficiencies in the Pinedale Basin, account for the difference in our planned budget for conversion of PUD volumes and our actual expenditures. Also, as previously disclosed, our 2015 drilling plan calls for increased drilling activity during the third quarter of 2015. With respect to conversion fractions, we concede to the Staff’s position that PUD volumes ‘dropped’ from the reserve portfolio are not equivalent to PUD volumes converted to development status.
In accordance with Question 131.04 of the Commission’s Compliance and Disclosure Interpretations, only those PUDs that have a projected positive cash flow and for which a final investment decision has been made are included in our reserve reports. While the Company has made the final investment decision to drill these PUDs at the time the applicable PUD is booked, the timing of such drilling is subject to change based on a number of factors, many of which are unpredictable and beyond our control, such as (i) changes in commodity prices, (ii) anticipated cash flows and projected rate of return, (iii) access to capital, (iv) new opportunities with better returns on investment that were not known at the time of the reserve report, (v) asset acquisitions and/or sales and (vi) actions or inactions of other co−owners or industry operators. As such, the relative proportion of total PUDs that the Company develops may not necessarily be uniform from year to year, but could vary by year based upon the foregoing factors. We attempt to maximize the rate of return on capital deployed, which requires that we continually review all investment options available. As a result, at times we may delay or remove the drilling of certain projects, including scheduled PUD development, in favor of projects with a more attractive rate of return. At the time when the Company makes a revision with respect to a PUD location, the associated PUD reserves are deferred or removed from the reserve report.
In the case of Vanguard, portfolio management in light of significant acquisitions has been the most significant factor driving management’s decision to divert drilling capital to projects not scheduled in the then current year’s development plan. As a result of acquisitions completed during 2012, 2013 and 2014, continuous changes in our drilling program including the drilling in the Arkoma Basin and a horizontal drilling plan in the Gulf Coast Basin, the development plan is periodically re-optimized, which has resulted in some reserves being dropped due to the fact they will not be drilled within five years from the booking date and other reserves being added due to acquisitions. These dropped PUDs are included in the “Revision” category of the PUD reconciliation as we account for dropped reserves as a revision to a previous estimate while the reserves added from acquisitions are included in the “Purchases of Reserves in Place” category.
Every year over the past three years, as a result of material acquisitions, management has made the decision to pursue other drilling opportunities through the course of a fiscal year in an effort to efficiently manage the Company’s portfolio of PUD inventory. For the most part, these opportunities were not available until these material acquisitions were completed. The performance of our company could suffer if management decided to keep the original drilling program established at the end of each previous year when we have better drilling opportunities available and thus the opportunity to achieve higher rates of return on invested drilling capital. Below is a summary of our recent material acquisitions completed during 2012, 2013 and 2014, which total approximately $2.3 billion of investment:
| |
| • | On June 29, 2012, we completed the acquisition of natural gas and liquids properties in the Woodford Shale in Oklahoma and the Fayetteville Shale in Arkansas of the Arkoma Basin from Antero Resources Corporation for an adjusted purchase price of $428.5 million with |
U.S. Securities and Exchange Commission
August 11, 2015
Page 4
an effective date for the acquisition of April 1, 2012 (the “Arkoma Basin Acquisition”). Through the Arkoma Basin Acquisition we acquired approximately 420 Bcfe of proved reserves with 42% being PUDs and 82% being natural gas.
| |
| • | On December 31, 2012, we completed the acquisition of natural gas and liquids properties in the Piceance Basin in Colorado and the Powder River and Wind River Basins in Wyoming from Bill Barrett Corporation for an adjusted purchase price of $324.7 million with an effective date of October 1, 2012 (the “Rockies Acquisition”). Through the Rockies Acquisition we acquired approximately 300 Bcfe of proved reserves with 20% being PUDs and 86% being natural gas. |
| |
| • | On April 1, 2013, we completed the acquisition of natural gas, oil and natural gas liquids properties in the Permian Basin from Range Resources Corporation for an adjusted purchase price of $266.2 million with an effective date of January 1, 2013 (the “Range Permian Acquisition”). Through the Range Permian Acquisition, we acquired approximately 137 Bcfe of proved reserves with 22% being PUDs and 43% being natural gas. |
| |
| • | On January 31, 2014, we completed the acquisition of natural gas and oil properties in the Pinedale and Jonah fields in Southwestern Wyoming for an adjusted purchase price of $555.6 million with an effective date of October 1, 2013 (the “Pinedale Acquisition”). Through the Pinedale Acquisition we acquired approximately 847 Bcfe of proved reserves with 57% being PUDs and 80% being natural gas. |
| |
| • | On August 29, 2014, we completed the acquisition of natural gas, oil and natural gas liquids properties in North Louisiana and East Texas for an adjusted purchase price of $265.1 million with an effective date of June 1, 2014 (the “Gulf Coast Acquisition”). Through the Gulf Coast Acquisition, we acquired approximately 150 Bcfe of proved reserves with 43% being PUDs and 71% being natural gas. |
| |
| • | On September 30, 2014, we completed the acquisition of natural gas, oil and NGLs assets in the Piceance Basin in Colorado for approximately $502.1 million in cash with an effective date of July 1, 2014 (the “Piceance Acquisition”). Through the Piceance Acquisition, we acquired additional interests in the same properties previously acquired in the Rockies Acquisition as defined above. We acquired approximately 389 Bcfe of proved reserves with 21% being PUDs and 77% being natural gas. |
Additionally, we are not the operator of a portion of our properties (approximately 47% of our proved reserves as of December 31, 2014) and, as a result, do not control final drilling decisions. For example, our development plan during 2013 was largely negatively impacted by the operators of our outside operated properties and their decision to postpone development. We further note that sometimes rather than deferring properties, our operators may opt to drill a location that was not booked as a proved location as a substitute for a planned PUD location. Such a decision could result in a lower conversion ratio, even though drilling capital is being spent to develop properties. In other cases, we have had to delay drilling because of permitting or other regulatory issues, as was the case with a Haynesville PUD well that was delayed this year.
In order to provide more clarity and give the Staff a better understanding of our decisions with respect to our drilling programs for each of 2012, 2013 and 2014, we have attached the following:
U.S. Securities and Exchange Commission
August 11, 2015
Page 5
| |
| • | Annex A contains the 12/31/2011 PUD Drilling Plan, including details on drilling plans for each of the five years in the plan, the year of initial booking and then information with respect to locations and volumes drilled and converted during 2012, locations and volumes dropped or divested during 2012 and locations and volumes added during 2012. |
| |
| • | Annex B contains the 12/31/2012 PUD Drilling Plan, including details on drilling plans for each of the five years in the plan, the year of initial booking and then information with respect to locations and volumes drilled and converted during 2013, locations and volumes dropped during 2013 and locations and volumes added during 2013. |
| |
| • | Annex C contains the 12/31/2013 PUD Drilling Plan, including details on drilling plans for each of the five years in the plan, the year of initial booking and then information with respect to locations and volumes drilled and converted during 2014, locations and volumes dropped or divested during 2014 and locations and volumes added during 2014. |
| |
| • | Annex D contains the 12/31/2014 PUD Drilling Plan, including details on drilling plans for each of the five years in the plan, the year of initial booking and then information with respect to locations and volumes drilled and converted during 2015. As of July 31, 2015, there have been no locations and volumes dropped or added during 2015. |
In closing, as reflected in the attached annexes, we should note the following details regarding PUD conversion.
With respect to the December 31, 2011 reserve report and development plan, we had anticipated (i) spending $29.1 million on drilling and converting PUDs and converting 16.6 Bcfe of PUD volumes during 2012, (ii) spending $32.3 million on drilling and converting PUDs and converting 16.2 Bcfe of PUD volumes during 2013, (iii) spending $27.4 million on drilling and converting PUDs and converting 15.2 Bcfe of PUD volumes during 2014 and (iv) spending $19.9 million on drilling and converting PUDs and converting 10.0 Bcfe of PUD volumes during 2015.
With respect to the December 31, 2012 reserve report and development plan, we had anticipated (i) spending $50.5 million on drilling and converting PUDs and converting 27.9 Bcfe of PUD volumes during 2013, (ii) spending $89.2 million on drilling and converting PUDs and converting 62.7 Bcfe of PUD volumes during 2014, and (iii) spending $87.9 million on drilling and converting PUDs and converting 57.9 Bcfe of PUD volumes during 2015.
With respect to the December 31, 2013 reserve report and development plan, we had anticipated (i) spending $18.9 million on drilling and converting PUDs and converting 24.6 Bcfe of PUD volumes during 2014 and (ii) spending $91.5 million on drilling and converting PUDs and converting 52.3 Bcfe of PUD volumes during 2015.
With respect to the December 31, 2014 reserve report and development plan, we had anticipated spending $105.7 million on drilling and converting PUDs and converting 101.9 Bcfe of PUD volumes during 2015.
We actually: (i) spent $18.5 million on drilling and converting volumes (inclusive of volumes not associated with proved locations) to PDP and converted 3.3 Bcfe to PDP volumes during 2012; (ii) spent $23.7 million on drilling and converting volumes (inclusive of volumes not associated with proved locations) to PDP and converted 14.8 Bcfe to PDP volumes during 2013; (iii) spent $32.9 million on drilling and converting volumes (inclusive of volumes not associated with proved locations)
U.S. Securities and Exchange Commission
August 11, 2015
Page 6
to PDP and converted 27.3 Bcfe to PDP volumes during 2014; and (iv) have spent $31.6 million on drilling and converting volumes (inclusive of volumes not associated with proved locations) to PDP and converted 47.3 Bcfe to PDP volumes during the first seven months of 2015. Additionally, during 2015, we have spent approximately $7.3 million on work in progress drilling wells that are not yet completed.
As disclosed in the Form 10−K, the Company’s annual reserve report is prepared based on studies performed by our internal reservoir engineers in accordance with guidelines established by the SEC. Our reserve estimation process is a collaborative effort coordinated by our reservoir engineers in compliance with our internal controls for such process. Once completed, our year-end reserves are presented to senior management, including the President and Chief Executive Officer, the Executive Vice President and Chief Financial Officer, and the Executive Vice President of Operations, for approval. The previously approved reserve report is then rolled forward to the next quarter by rolling off the current quarter production, adding to the database any new leases from acquisitions, and moving PUDs drilled and completed to PDP status in the quarter. Any necessary changes to the original assumptions attributed to PUDs that may arise from changes related to final investment decisions (resulting from new acquisitions, updated drilling information from operators, etc.) and sufficient actual production data during the quarter (at least a month’s worth of production) are made to the database (i.e. initial production rate, decline rate, LOE rate, etc.) and reviewed and approved by the Company executive management.
As disclosed in the Form 10−K, we also engage independent petroleum engineers to audit a substantial portion of our reserve estimates. Our audit procedures require the independent engineers to prepare their own estimates of proved reserves for properties comprising at least 80% of our year-end proved reserves. Our Board of Directors requires that the independent petroleum engineers’ estimate of reserve quantities for the properties audited by the independent petroleum engineers are within 10% of our internal estimate. For the year ended December 31, 2014, we engaged DeGolyer and MacNaughton (“D&M”), an independent petroleum engineering firm, to perform reserve audit services. The opinion by D&M for the year ended December 31, 2014 covered producing areas containing 80.7% of our proved reserves on a net-gas-equivalent basis. D&M’s opinion indicates that the estimates of proved reserves prepared by our internal reserves engineers for the properties reviewed by D&M, when compared in total on a net-gas-equivalent basis, in aggregate, are reasonable. Such estimates prepared by D&M in the aggregate were within our 10% variation tolerance when compared to those prepared by our reserves engineering group.
We consider our current internal controls in conjunction with reserve estimation are adequate in addressing all significant risks surrounding our disclosed reserves.
In future filings, we propose to include more detail regarding the volume of PUDs dropped from the drilling schedule and specific reasons for such change in the drilling program. We also propose to include additional details on PUDs added by acquisition during a particular year and if any of those acquired PUD locations were drilled in place of PUD locations as scheduled for drilling in the year end drilling program.
*****
U.S. Securities and Exchange Commission
August 11, 2015
Page 7
The Company 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 the Company from its full responsibility for the adequacy and accuracy of the disclosure in the filing; and |
| |
| • | the Company 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. |
Please direct any questions or comments you have regarding our response to comment number 2 of the Comment Letter, LRE/Vanguard Amendment No. 3, EROC/Vanguard Amendment No. 3 or the Vanguard Form 10-K to undersigned by phone at (832) 327-2259 or Douglas V. Getten of Paul Hastings LLP at (713) 860-7340.
Very truly yours,
|
| |
| By: | /s/ Scott W. Smith |
| | Scott W. Smith |
| | President and Chief Executive Officer |
| | Vanguard Natural Resources, LLC |
cc: Scott W. Smith, President, Chief Executive Officer and Director, Vanguard Natural Resources, LLC
Douglas V. Getten, Partner, Paul Hastings LLP
U.S. Securities and Exchange Commission
August 11, 2015
Page 8
ANNEX A
The development plan, as of December 31, 2011, for converting our PUDs to PDP during each of the next five fiscal years is set forth below:
|
| | | | | | | | | | | | | | | | |
| | Year of Initial Booking | Number of
PUD Net Wells Planned to be Drilled | Natural Gas PUD Reserves
to be Converted,
Bcf | Oil PUD Reserves
to be Converted,
MMBbls | NGL PUD Reserves
to be Converted,
MMBbls | Total PUD Reserves
to be Converted,
Bcfe | Percent of Total Year End 2011 PUD Reserves | Capital Scheduled to be Spent (in thousands) |
| | 2007 | 7 |
| 1.1 |
| — |
| — |
| 1.1 |
| 2 | % | |
| | 2008 | — |
| — |
| — |
| — |
| — |
| — |
| |
| | 2009 | 3 |
| 0.6 |
| 0.7 |
| 0.1 |
| 5.5 |
| 8 | % | |
| | 2010 | 13 |
| 1.3 |
| 1.3 |
| — |
| 8.8 |
| 13 | % | |
| | 2011 | 2 |
| 0.1 |
| 0.2 |
| — |
| 1.2 |
| 2 | % | |
| 2012 | | 25 |
| 3.1 |
| 2.2 |
| 0.1 |
| 16.6 |
| 25 | % |
| $29,145 |
|
| | | | | | | | | |
| | 2008 | 23 |
| 3.2 |
| — |
| 0.5 |
| 5.6 |
| 8 | % | |
| | 2009 | 12 |
| 3.7 |
| 0.5 |
| — |
| 6.3 |
| 10 | % | |
| | 2010 | 6 |
| 1.4 |
| 0.4 |
| — |
| 3.6 |
| 5 | % | |
| | 2011 | 1 |
| 0.1 |
| 0.1 |
| — |
| 0.6 |
| 1 | % | |
| 2013 | | 42 |
| 8.4 |
| 1.0 |
| 0.5 |
| 16.1 |
| 24 | % |
| $32,349 |
|
| | | | | | | | | |
| | 2009 | 39 |
| 5.8 |
| — |
| 0.3 |
| 8.0 |
| 12 | % | |
| | 2010 | 8 |
| 2.6 |
| 0.7 |
| — |
| 6.5 |
| 10 | % | |
| | 2011 | 1 |
| 0.1 |
| 0.1 |
| — |
| 0.7 |
| 1 | % | |
| 2014 | | 48 |
| 8.5 |
| 0.8 |
| 0.3 |
| 15.2 |
| 23 | % |
| $27,351 |
|
| | | | | | | | | |
| | 2010 | 33 |
| 3.6 |
| 0.3 |
| — |
| 5.4 |
| 8 | % | |
| | 2011 | 10 |
| 2.3 |
| 0.1 |
| 0.2 |
| 4.6 |
| 7 | % | |
| 2015 | | 43 |
| 5.9 |
| 0.4 |
| 0.2 |
| 10.0 |
| 15 | % |
| $19,905 |
|
| | | | | | | | | |
| | 2011 | 40 |
| 5.5 |
| 0.4 |
| 0.1 |
| 8.7 |
| 13 | % | |
| 2016 | | 40 |
| 5.5 |
| 0.4 |
| 0.1 |
| 8.7 |
| 13 | % |
| $19,522 |
|
| | | | | | | | | |
| Total | | 198 |
| 31.4 |
| 4.8 |
| 1.2 |
| 66.6 |
| 100.0 | % |
| $128,272 |
|
2012 actual results of the December 31, 2011 development plan are set forth below:
2012 Conversion of Year End 2011 PUD Reserves
|
| | | | | | |
| | Year of Initial Booking | Number of
PUD Net Wells Drilled | Total PUD Reserves
Converted,
Bcfe | Capital Spent (in thousands) |
| 2012 | 2010 | 3.0 | 1.8 |
| $6,075 |
|
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August 11, 2015
Page 9
2012 Conversion of Other Volumes into PDP
|
| | | | | | |
| | Year of Initial Booking | Number of
Wells Converted to PDP | Total Volume Converted to PDP, Bcfe | Capital Spent (in thousands) |
| 2012 | N/A(a) | 2.7 | 1.5 |
| $12,390 |
|
| |
| (a) | These volumes were not booked as PUDs at 12/31/2011, but we owned the properties associated with these locations at 12/31/2011. During 2012, we drilled and completed non-proved locations in order to convert those volumes into PDP. |
Year End 2011 PUD Reserves Divested during 2012 (b)
|
| | | | | | |
| Year of Initial Booking | Year Initially Scheduled to be Drilled | Number of
PUD Net Wells Dropped | Total PUD Reserves
Dropped,
Bcfe | Capital Dropped (in thousands) |
| 2007 | 2012 | 7 | 1.1 |
| $1,695 |
|
| 2008 | 2013 | 24 | 3.2 |
| $6,455 |
|
| 2009 | 2014 | 28 | 3.0 |
| $7,844 |
|
| 2010 | 2015 | 28 | 2.9 |
| $7,592 |
|
| 2011 | 2016 | 27 | 3.0 |
| $7,892 |
|
| | | 114 | 13.2 |
| $31,478 |
|
| |
| (b) | On March 30, 2012, we divested 13.2 Bcfe of PUD Reserves in connection with the sale of our oil and natural gas properties located in the Appalachian Basin. |
Year End 2011 PUD Reserves Dropped during 2012 (c)
|
| | | | | | |
| Year of Initial Booking | Year Initially Scheduled to be Drilled | Number of
PUD Net Wells Dropped | Total PUD Reserves
Dropped,
Bcfe | Capital Dropped (in thousands) |
| 2010 | 2012 | 0 | 0.0 |
| $130 |
|
| 2011 | 2012 | 1 | 1.0 |
| $986 |
|
| | 2016 | 1 | 0.1 |
| $435 |
|
| | | 2 | 1.1 |
| $1,551 |
|
| |
| (c) | Due to falling commodity prices during 2012 and the unscheduled spending of $12.4 million on drilling and completion projects, we converted 1.5 Bcfe to PDP that projected better rates of return than the initially scheduled PUDs and dropped 1 net well with associated reserves of 1.0 Bcfe planned for 2012 from the five year development schedule. Additionally, as a result of our 2013 forward ranking of available drilling and completion projects based on expected rates of return, we dropped 1 net well with associated reserves of 0.1 Bcfe from the five year development plan as it did not rank high enough to plan capital spending for this well within five years. |
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August 11, 2015
Page 10
PUD Reserves Acquired during 2012
|
| | |
| Year of Initial Booking | Number of
PUD Net Wells Added | Total PUD Reserves
Added,
Bcfe |
| 2012 | 68 | 185.9 |
PUD Reserves Added to Five Year Plan during 2012
|
| | |
| Year of Initial Booking | Number of
PUD Net Wells Added | Total PUD Reserves
Added,
Bcfe |
| 2012 | 3 | 3.0 |
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August 11, 2015
Page 11
ANNEX B
The development plan, as of December 31, 2012, for converting our PUDs to PDP during each of the next five fiscal years is set forth below:
|
| | | | | | | | | | | | | | | | |
| | Year of Initial Booking | Number of
PUD Net Wells Planned to be Drilled | Natural Gas PUD Reserves
to be Converted,
Bcf | Oil PUD Reserves
to be Converted,
MMBbls | NGL PUD Reserves
to be Converted,
MMBbls | Total PUD Reserves
to be Converted,
Bcfe | Percent of Total Year End 2012 PUD Reserves | Capital Scheduled to be Spent (in thousands) |
| | 2008 | — |
| — |
| — |
| — |
| — |
| — |
| |
| | 2009 | 1 |
| 0.3 |
| — |
| — |
| 0.5 |
| — |
| |
| | 2010 | 1 |
| 0.2 |
| 0.1 |
| — |
| 1.1 |
| 1 | % | |
| | 2011 | — |
| — |
| — |
| — |
| — |
| — |
| |
| | 2012 | 26 |
| 23.0 |
| 0.4 |
| 0.2 |
| 26.3 |
| 11 | % | |
| 2013 | | 28 |
| 23.5 |
| 0.5 |
| 0.2 |
| 27.9 |
| 12 | % |
| $50,515 |
|
| | | | | | | | | |
| | 2009 | 14 |
| 3.6 |
| 0.7 |
| 0.4 |
| 10.5 |
| 4 | % | |
| | 2010 | 10 |
| 1.8 |
| 0.6 |
| — |
| 5.4 |
| 2 | % | |
| | 2011 | 1 |
| 0.1 |
| 0.1 |
| — |
| 0.5 |
| — |
| |
| | 2012 | 17 |
| 26.1 |
| 0.3 |
| 3.1 |
| 46.3 |
| 20 | % | |
| 2014 | | 42 |
| 31.6 |
| 1.7 |
| 3.5 |
| 62.7 |
| 26 | % |
| $89,218 |
|
| | | | | | | | | |
| | 2010 | 21 |
| 5.2 |
| 1.1 |
| 0.4 |
| 13.8 |
| 6 | % | |
| | 2011 | 11 |
| 2.4 |
| 0.2 |
| 0.2 |
| 5.2 |
| 2 | % | |
| | 2012 | 11 |
| 31.5 |
| — |
| 1.2 |
| 38.9 |
| 16 | % | |
| 2015 | | 43 |
| 39.1 |
| 1.3 |
| 1.8 |
| 57.9 |
| 24 | % |
| $87,950 |
|
| | | | | | | | | |
| | 2011 | 20 |
| 4.0 |
| 0.8 |
| 0.1 |
| 10.0 |
| 5 | % | |
| | 2012 | 11 |
| 25.8 |
| — |
| 2.5 |
| 40.5 |
| 17 | % | |
| 2016 | | 31 |
| 29.8 |
| 0.8 |
| 2.6 |
| 50.5 |
| 22 | % |
| $79,715 |
|
| | | | | | | | | |
| | 2012 | 13 |
| 22.5 |
| 0.3 |
| 2.4 |
| 38.6 |
| 16 | % | |
| 2017 | | 13 |
| 22.5 |
| 0.3 |
| 2.4 |
| 38.6 |
| 16 | % |
| $59,136 |
|
| | | | | | | | | |
| Total | | 157 |
| 146.5 |
| 4.6 |
| 10.5 |
| 237.6 |
| 100.0 | % |
| $366,534 |
|
2013 actual results of the December 31, 2012 development plan are set forth below:
U.S. Securities and Exchange Commission
August 11, 2015
Page 12
2013 Conversion of Year End 2012 PUD Reserves
|
| | | | | | |
| | Year of Initial Booking | Number of
PUD Net Wells Drilled | Total PUD Reserves
Converted,
Bcfe | Capital Spent (in thousands) |
| | 2010 | 0.2 | 0.5 | |
| | 2012 | 1.7 | 4.3 | |
| 2013 | | 1.9 | 4.8 |
| $8,965 |
|
2013 Conversion of Other Volumes into PDP
|
| | | | | | |
| | Year of Initial Booking | Number of
Wells Converted to PDP | Total Volume Converted to PDP, Bcfe | Capital Spent (in thousands) |
| 2013 | N/A(a) | 4.7 | 10.0 |
| $14,704 |
|
| |
| (a) | These volumes were not booked as PUDs at 12/31/2012, but we owned the properties associated with these locations at 12/31/2012. During 2013, we drilled and completed non-proved locations in order to convert those volumes into PDP. |
Year End 2012 PUD Reserves Dropped during 2013 (b)
|
| | | | | | | |
| Year of Initial Booking | Year Initially Scheduled to be Drilled | Number of
PUD Net Wells Dropped | Total PUD Reserves
Dropped,
Bcfe | Capital Dropped (in thousands) |
| 2009 | 2013 | 1 |
| 0.5 |
| $609 |
|
| | 2014 | 12 |
| 7.3 |
| $8,874 |
|
| 2010 | 2013 | — |
| 0.2 |
| $450 |
|
| | 2014 | 4 |
| 2.0 |
| $4,822 |
|
| | 2015 | 12 |
| 6.7 |
| $8,981 |
|
| 2011 | 2014 | 1 |
| 0.6 |
| $506 |
|
| | 2015 | 11 |
| 5.3 |
| $6,812 |
|
| | 2016 | 10 |
| 4.8 |
| $8,680 |
|
| 2012 | 2013 | 15 |
| 12.8 |
| $26,777 |
|
| | 2014 | 2 |
| 4.8 |
| $7,372 |
|
| | 2015 | 4 |
| 12.9 |
| $19,874 |
|
| | 2016 | 1 |
| 4.3 |
| $6,575 |
|
| | 2017 | 1 |
| 3.9 |
| $6,376 |
|
| | | 74 |
| 66.1 |
| $106,708 |
|
| |
| (b) | Due to continued weakness in gas prices during the first half of 2013 and the unscheduled spending of $14.7 million on drilling and completion projects, we added 10.0 Bcfe to PDP that projected better rates of return than the initially scheduled PUDs and dropped 16 net wells with associated reserves of 13.5 Bcfe planned for 2013 from the five year development schedule. Additionally, as a result of the properties acquired in the Range Permian Acquisition and the |
U.S. Securities and Exchange Commission
August 11, 2015
Page 13
subsequent 2014 forward ranking of available drilling and completion projects based on expected rates of return, we dropped 39 net wells with associated reserves of 25.3 Bcfe from the five year development plan as they did not rank high enough to plan capital spending for these wells within five years. Furthermore, as a result of increased capital costs and operating expenses realized throughout the year, we determined that 19 net wells with associated reserves of 27.3 Bcfe were uneconomic at management’s expectation of future pricing and removed them from the 2014 forward five year development plan.
PUD Reserves Acquired during 2013
|
| | |
| Year of Initial Booking | Number of
PUD Net Wells Added | Total PUD Reserves
Added,
Bcfe |
| 2013 | 45 | 31.3 |
PUD Reserves Added to Five Year Plan during 2013
|
| | |
| Year of Initial Booking | Number of
PUD Net Wells Added | Total PUD Reserves
Added,
Bcfe |
| 2013 | 17 | 35.6 |
U.S. Securities and Exchange Commission
August 11, 2015
Page 14
ANNEX C
The development plan, as of December 31, 2013, for converting our PUDs to PDP during each of the next five fiscal years is set forth below:
|
| | | | | | | | | | | | | | | | |
| | Year of Initial Booking | Number of
PUD Net Wells Planned to be Drilled | Natural Gas PUD Reserves
to be Converted,
Bcf | Oil PUD Reserves
to be Converted,
MMBbls | NGL PUD Reserves
to be Converted,
MMBbls | Total PUD Reserves
to be Converted,
Bcfe | Percent of Total Year End 2013 PUD Reserves | Capital Scheduled to be Spent (in thousands) |
| | 2009 | — |
| — |
| 0.1 |
| — |
| 0.6 |
| 0.3 | % | |
| | 2010 | — |
| — |
| 0.1 |
| — |
| 0.6 |
| 0.3 | % | |
| | 2011 | 1 |
| — |
| — |
| — |
| — |
| — |
| |
| | 2012 | 3 |
| 6.7 |
| — |
| 0.4 |
| 9.1 |
| 4.0 | % | |
| | 2013 | 5 |
| 9.5 |
| 0.2 |
| 0.6 |
| 14.3 |
| 6.4 | % | |
| 2014 | | 9 |
| 16.2 |
| 0.4 |
| 1.0 |
| 24.6 |
| 11.0 | % |
| $18,859 |
|
| | | | | | | | | |
| | 2010 | 1 |
| — |
| — |
| — |
| — |
| — |
| |
| | 2011 | 12 |
| 0.2 |
| 1.1 |
| — |
| 6.8 |
| 3.3 | % | |
| | 2012 | 8 |
| 13.8 |
| 0.1 |
| 1.4 |
| 22.8 |
| 10.3 | % | |
| | 2013 | 26 |
| 9.5 |
| 1.5 |
| 0.7 |
| 22.7 |
| 10.4 | % | |
| 2015 | | 47 |
| 23.5 |
| 2.7 |
| 2.1 |
| 52.3 |
| 24.0 | % |
| $91,484 |
|
| | | | | | | | | |
| | 2011 | 12 |
| 0.3 |
| 0.7 |
| — |
| 4.5 |
| 2.1 | % | |
| | 2012 | 16 |
| 28.1 |
| 0.4 |
| 1.8 |
| 41.4 |
| 18.4 | % | |
| | 2013 | 15 |
| 11.6 |
| 0.3 |
| 1.0 |
| 19.4 |
| 8.5 | % | |
| 2016 | | 43 |
| 40.0 |
| 1.4 |
| 2.8 |
| 65.3 |
| 29.0 | % |
| $98,214 |
|
| | | | | | | | | |
| | 2012 | 22 |
| 33.0 |
| 0.2 |
| 2.7 |
| 50.4 |
| 22.3 | % | |
| | 2013 | 11 |
| 6.2 |
| 0.3 |
| 0.5 |
| 11.0 |
| 4.7 | % | |
| 2017 | | 33 |
| 39.2 |
| 0.5 |
| 3.2 |
| 61.4 |
| 27.0 | % |
| $90,786 |
|
| | | | | | | | | |
| | 2013 | 11 |
| 12.4 |
| 0.2 |
| 1.1 |
| 20.2 |
| 9.0 | % | |
| 2018 | | 11 |
| 12.4 |
| 0.2 |
| 1.1 |
| 20.2 |
| 9.0 | % |
| $32,661 |
|
| | | | | | | | | |
| Total | | 143 |
| 131.3 |
| 5.2 |
| 10.2 |
| 223.8 |
| 100.0 | % |
| $332,004 |
|
2014 actual results of the December 31, 2013 development plan are set forth below:
U.S. Securities and Exchange Commission
August 11, 2015
Page 15
2014 Conversion of Year End 2013 PUD Reserves
|
| | | | | | | | |
| | Year of Initial Booking | Number of
PUD Net Wells Drilled | Total PUD Reserves
Converted,
Bcfe | Capital Spent (in thousands) |
| | 2009 | 0.2 |
| 1.3 |
| |
| | 2010 | 0.2 |
| 0.3 |
| |
| | 2011 | — |
| — |
| |
| | 2012 | 1.6 |
| 6.3 |
| |
| | 2013 | 4.3 |
| 13.2 |
| |
| 2014 | | 6.3 |
| 21.1 |
|
| $16,596 |
|
2014 Conversion of Other Volumes into PDP
|
| | | | | | |
| | Year of Initial Booking | Number of
Wells Converted to PDP | Total Volume Converted to PDP, Bcfe | Capital Spent (in thousands) |
| 2014 | N/A(a) | 6.0 | 6.18 |
| $16,262 |
|
| |
| (a) | These volumes were not booked as PUDs at 12/31/2013, but we owned the properties associated with these locations at 12/31/2013. During 2014, we drilled and completed non-proved locations in order to convert those volumes into PDP. |
Year End 2013 PUD Reserves Divested during 2014 (b)
|
| | | | | | |
| Year of Initial Booking | Year Initially Scheduled to be Drilled | Number of
PUD Net Wells Divested | Total PUD Reserves
Divested,
Bcfe | Capital Dropped (in thousands) |
| 2011 | 2015 | 1 | 0.2 |
| $375 |
|
| |
| (b) | On December 16, 2014 we divested 0.2 Bcfe of PUD Reserves in connection with the sale of some of our oil and natural gas properties located in the Wind River Basin. |
U.S. Securities and Exchange Commission
August 11, 2015
Page 16
Year End 2013 PUD Reserves Dropped during 2014 (c)
|
| | | | | | | | |
| Year of Initial Booking | Year Initially Scheduled to be Drilled | Number of
PUD Net Wells Dropped | Total PUD Reserves
Dropped,
Bcfe | Capital Dropped (in thousands) |
| 2011 | 2016 | 1 |
| 0.2 |
|
| $630 |
|
| 2012 | 2014 | — |
| — |
|
| $59 |
|
| | 2015 | 1 |
| 5.8 |
|
| $6,015 |
|
| | 2016 | 7 |
| 25.3 |
|
| $32,669 |
|
| | 2017 | 14 |
| 39.8 |
|
| $55,890 |
|
| 2013 | 2014 | — |
| 0.2 |
|
| $222 |
|
| | 2015 | 3 |
| 1.7 |
|
| $6,720 |
|
| | 2016 | 4 |
| 12.8 |
|
| $22,612 |
|
| | 2017 | 1 |
| 3.3 |
|
| $6,157 |
|
| | 2018 | 5 |
| 13.2 |
|
| $22,334 |
|
| | | 36 |
| 102.3 |
|
| $153,308 |
|
| |
| (c) | Acquisition activity during 2014 resulted in our participation in the continuous drilling programs of the operators, Ultra Petroleum Corp. and QEP Resources, Inc. in development of high BTU gas in the Pinedale field. We immediately allocated capital to these drilling and completion projects and 54.0 Bcfe and 18 net wells booked as PUDs in the first quarter of 2014 were converted during the remainder of the year. Additionally, following the Gulf Coast Acquisition of assets in North Louisiana, management decided to allocate capital to an operated drilling program targeting high BTU gas which began in 2015. These two acquisitions and subsequent management decisions resulted in the dropping of 31 net wells with associated reserves of 87.5 Bcfe from the 2015 forward five year development plan. Finally, increased drilling, completing, and operating expenses realized in 2014 resulted in the dropping of 5 net wells with associated reserves of 14.8 Bcfe because these wells were no longer considered economic. |
PUD Reserves Acquired during 2014
|
| | |
| Year of Initial Booking | Number of
PUD Net Wells Added | Total PUD Reserves
Added,
Bcfe |
| 2014 | 236 | 517.4 |
PUD Reserves Added to Five Year Plan during 2014
|
| | |
| Year of Initial Booking | Number of
PUD Net Wells Added | Total PUD Reserves
Added,
Bcfe |
| 2014 | 35 | 42.2 |
U.S. Securities and Exchange Commission
August 11, 2015
Page 17
2014 Conversion of 2014 Acquisition PUD Reserves
|
| | | | | |
| Year of Initial Booking | Number of
PUD Net Wells Drilled | Total PUD Reserves
Converted,
Bcfe | Capital Spent (in thousands) |
| 2014 | 18 | 54.0 |
| $58,891 |
|
U.S. Securities and Exchange Commission
August 11, 2015
Page 18
ANNEX D
The development plan, as of December 31, 2014, for converting our PUDs to PDP during each of the next five fiscal years is set forth below:
|
| | | | | | | | | | | | | | | |
| | Year of Initial Booking | Number of
PUD Net Wells Planned to be Drilled | Natural Gas PUD Reserves
to be Converted,
Bcf | Oil PUD Reserves
to be Converted,
MMBbls | NGL PUD Reserves
to be Converted,
MMBbls | Total PUD Reserves
to be Converted,
Bcfe | Percent of Total Year End 2014 PUD Reserves | Capital Scheduled to be Spent (in thousands) |
| | 2010 | — |
| — |
| — |
| — |
| 0.1 | — |
| |
| | 2011 | 2 |
| — |
| 0.3 |
| — |
| 1.9 | 0.3 | % | |
| | 2012 | 9 |
| 1.7 |
| — |
| — |
| 1.7 | 0.3 | % | |
| | 2013 | 8 |
| 0.8 |
| 0.8 |
| 0.1 |
| 6.0 | 0.9 | % | |
| | 2014 | 25 |
| 76.9 |
| 0.9 |
| 1.7 |
| 92.2 | 14.1 | % | |
| 2015 | | 44 |
| 79.4 |
| 2.0 |
| 1.8 |
| 101.9 | 15.6 | % |
| $105,673 |
|
| | | | | | | | | |
| | 2011 | 16 |
| 3.7 |
| 0.8 |
| — |
| 8.6 | 1.3 | % | |
| | 2012 | 13 |
| 13.2 |
| 0.4 |
| 0.6 |
| 19.2 | 2.9 | % | |
| | 2013 | 9 |
| 7.2 |
| 0.3 |
| 0.5 |
| 11.8 | 1.8 | % | |
| | 2014 | 42 |
| 71.3 |
| 1.1 |
| 1.8 |
| 88.5 | 13.5 | % | |
| 2016 | | 80 |
| 95.4 |
| 2.6 |
| 2.9 |
| 128.1 | 19.6 | % |
| $165,172 |
|
| | | | | | | | | |
| | 2012 | 37 |
| 30.8 |
| 0.8 |
| 0.9 |
| 41.2 | 6.3 | % | |
| | 2013 | 11 |
| 4.0 |
| 0.5 |
| 0.3 |
| 8.0 | 1.2 | % | |
| | 2014 | 43 |
| 78.3 |
| 1.4 |
| 1.8 |
| 98.2 | 15.0 | % | |
| 2017 | | 91 |
| 113.1 |
| 2.7 |
| 3.0 |
| 147.4 | 22.6 | % |
| $190,439 |
|
| | | | | | | | | |
| | 2013 | 17 |
| 6.1 |
| 0.5 |
| 0.4 |
| 11.8 | 1.8 | % | |
| | 2014 | 66 |
| 102.6 |
| 1.4 |
| 2.5 |
| 126.4 | 19.3 | % | |
| 2018 | | 83 |
| 108.7 |
| 1.9 |
| 2.9 |
| 138.2 | 21.1 | % |
| $180,884 |
|
| | | | | | | | | |
| | 2014 | 73 |
| 108.6 |
| 1.7 |
| 3.2 |
| 138.1 | 21.1 | % | |
| 2019 | | 73 |
| 108.6 |
| 1.7 |
| 3.2 |
| 138.1 | 21.1 | % |
| $164,187 |
|
| | | | | | | | | |
| Total | | 371 |
| 505.2 |
| 10.9 |
| 13.8 |
| 653.7 | 100.0 | % |
| $806,355 |
|
Year to date 2015 actual results of the December 31, 2014 development plan are set forth below:
2015 Conversion of Year End 2014 PUD Reserves (through July 31, 2015)
|
| | | | | | |
| | Year of Initial Booking | Number of
PUD Net Wells Drilled | Total PUD Reserves
Converted,
Bcfe | Capital Spent (in thousands) (a) |
| 2015 | 2014 | 13 | 47.3 |
| $31,632 |
|
(a) Excludes capital spent of approximately $7.3 million on work in progress drilling wells that are not yet completed.
