0000077877-16-000058.txt : 20160616 0000077877-16-000058.hdr.sgml : 20160616 20160129112357 ACCESSION NUMBER: 0000077877-16-000058 CONFORMED SUBMISSION TYPE: CORRESP PUBLIC DOCUMENT COUNT: 2 FILED AS OF DATE: 20160129 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PDC ENERGY, INC. CENTRAL INDEX KEY: 0000077877 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 952636730 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: CORRESP BUSINESS ADDRESS: STREET 1: 1775 SHERMAN STREET STREET 2: SUITE 3000 CITY: DENVER STATE: CO ZIP: 80203 BUSINESS PHONE: 303-860-5800 MAIL ADDRESS: STREET 1: PDC ENERGY, INC. STREET 2: 1775 SHERMAN ST CITY: SUITE 3000 STATE: CO ZIP: 80203 FORMER COMPANY: FORMER CONFORMED NAME: PETROLEUM DEVELOPMENT CORP DATE OF NAME CHANGE: 19920703 FORMER COMPANY: FORMER CONFORMED NAME: YELLOW WING URANIUM CORP DATE OF NAME CHANGE: 19730606 CORRESP 1 filename1.htm CORRESP
United States Securities and Exchange Commission
Division of Corporation Finance
January 29, 2016
Page 1


January 29, 2016
Via EDGAR

Office of Natural Resources
Division of Corporation Finance
United States Securities and Exchange Commission
Mail Stop 4628
100 F Street, NE
Washington, DC 20549
Attention: Brad Skinner, Senior Assistant Chief Accountant
Wei Lu, Staff Accountant
    
Re:    PDC Energy, Inc.
Form 10-K for the Fiscal Year Ended December 31, 2014
Filed February 19, 2015
File No. 000-07246
Ladies and Gentlemen:
With respect to the comments of the staff of the Division of Corporation Finance of the Securities and Exchange Commission (the “Commission”) set forth in its comment letter dated December 21, 2015 (the “Comment Letter”) relating to the Annual Report on Form 10-K for the fiscal year ended December 31, 2014 and filed on February 19, 2015 (the “Annual Report”) by PDC Energy, Inc. (the “Company”), the Company responds as follows:
The comments of the staff are set forth below for ease of reference, and are numbered to correspond to the numbered comments in the Comment Letter.
Form 10-K for Fiscal Year Ended December 31, 2014
Business and Properties, page 2
Our Strengths
1.
Disclosure under this section indicates, in part, that you have “inventory of approximately 2,650 gross proved undeveloped and probable horizontal drilling projects.” Tell us how many of these locations are included in your reported proved reserves as of December 31, 2014. Additionally, given the different levels of certainty associated with proved and probable reserves, explain to us your basis for concluding that presentation of a combined total for these locations is appropriate.
Response:
Of the inventory of approximately 2,650 gross proved undeveloped (“PUD”) and probable locations, 774 were included in our proved reserves as PUD reserves in the reserve report dated December 31, 2014, as prepared


United States Securities and Exchange Commission
Division of Corporation Finance
January 29, 2016
Page 2

by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineering consulting firm. The remaining approximately 1,876 locations were in the probable category, primarily because they were not scheduled to be developed within five years of initial booking or they are downspaced locations. We believe that the combined presentation was appropriate in light of the degree of similarity between the proved and probable locations from a geologic perspective. Nevertheless, we propose that when reporting drilling locations in our Annual Report on Form 10-K for the year ended December 31, 2015 and future years, we will present separately, rather than combine, drilling locations that are associated with PUD reserves included in our reserve report and those associated with probable locations.
Notes to Consolidated Financial Statements
Crude Oil and Natural Gas Information, page 88
2.
We note that during each of the last three years, you have converted 10% or less of your beginning-of-the-year proved undeveloped reserves (“PUDs”), which is significantly less than the 20% annual conversion rate implied by the five-year limitation applicable to PUDs. To help us understand the activity related to your reported PUD volumes, provide us with an aging and roll-forward, for your reported PUD balances as of each of the years ending December 31, 2014, December 31, 2013 and December 31, 2012, that shows the year-end balance broken down by the year in which the volumes were originally booked, and all changes/revisions, also by year booked, that have been made to those volumes since initially being reported as proved undeveloped reserves.
Response:
As requested by the Staff, the following tables summarize the PUD reserve balances for each of the years ending December 31, 2014 (Table 3), 2013 (Table 2) and 2012 (Table 1), showing year-end balances broken down by the year in which the volumes were originally booked. All changes/revisions, also by year booked, that have been made to those volumes since initially being reported as proved undeveloped reserves are also summarized in the tables.


United States Securities and Exchange Commission
Division of Corporation Finance
January 29, 2016
Page 3

Table 1 (MBoe)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year of Initial Booking
 
Beginning Proved Undeveloped Reserves, January 1, 2012
 
Converted to Developed
 
Revisions from Changes in Development Plan
 
Revisions due to Pricing, Updated Interests & Expenses
 
Revisions due to Type Curve Adjustments & Other Factors
 
Total Revisions to Previous Estimates
 
Purchases, Dispositions, Extensions, Discoveries and Other Additions
 
Ending Proved Undeveloped Reserves, December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2009
 
31,638

 
(3,883
)
 
(18,715
)
 
(755
)
 
(4,417
)
 
(23,887
)
 
(3,868
)
 
—

2010
 
12,724

 
(408
)
 
(3,222
)
 
(624
)
 
2,176

 
(1,670
)
 
(2,653
)
 
7,993

2011
 
46,328

 
(3,364
)
 
(16,353
)
 
(920
)
 
2,509

 
(14,764
)
 
(7,161
)
 
21,039

2012
 
—

 
—

 
—

 
—

 
—

 
—

 
82,025

 
82,025

 
 
90,690

 
(7,655
)
 
(38,290
)
 
(2,299
)
 
268

 
(40,321
)
 
68,343

 
111,057

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Table 2 (MBoe)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year of Initial Booking
 
Ending Proved Undeveloped Reserves, December 31, 2012
 
Converted to Developed
 
Revisions from Changes in Development Plan
 
Revisions due to Pricing, Updated Interests & Expenses
 
Revisions due to Type Curve Adjustments & Other Factors
 
Total Revisions to Previous Estimates
 
Purchases, Dispositions, Extensions, Discoveries and Other Additions
 
Ending Proved Undeveloped Reserves, December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2010
 
7,993

 
(511
)
 
(4,537
)
 
39

 
632

 
(3,866
)
 
(464
)
 
3,152

2011
 
21,039

 
(1,110
)
 
(11,496
)
 
1,677

 
1,289

 
(8,530
)
 
(1,111
)
 
10,288

2012
 
82,025

 
(1,591
)
 
(32,853
)
 
869

 
4,651

 
(27,333
)
 
(1,463
)
 
51,638

2013
 
—

 
—

 
—

 
—

 
—

 
—

 
125,143

 
125,143

 
 
111,057

 
(3,212
)
 
(48,886
)
 
2,585

 
6,572

 
(39,729
)
 
122,105

 
190,221

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Table 3 (MBoe)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year of Initial Booking
 
Ending Proved Undeveloped Reserves, December 31, 2013
 
Converted to Developed
 
Revisions from Changes in Development Plan
 
Revisions due to Pricing, Updated Interests & Expenses
 
Revisions due to Type Curve Adjustments & Other Factors
 
Total Revisions to Previous Estimates
 
Purchases, Dispositions, Extensions, Discoveries and Other Additions
 
Ending Proved Undeveloped Reserves, December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2010
 
3,152

 
—

 
—

 
—

 
—

 
—

 
(3,152
)
 
—

2011
 
10,288

 
—

 
(507
)
 
142

 
78

 
(287
)
 
(5,540
)
 
4,461

2012
 
51,638

 
(2,431
)
 
(16,096
)
 
(56
)
 
(40
)
 
(16,192
)
 
(5,350
)
 
27,665

2013
 
125,143

 
(10,299
)
 
(37,111
)
 
(950
)
 
12,542

 
(25,519
)
 
(25,795
)
 
63,530

2014
 
—

 
—

 
—

 
—

 
—

 
—

 
79,568

 
79,568

 
 
190,221

 
(12,730
)
 
(53,714
)
 
(864
)
 
12,580

 
(41,998
)
 
39,731

 
175,224



Further explanation of these tables has been provided in our responses to Comments 3 and 4, below.

3.
We note that during each of the years ended December 31, 2014, December 31, 2013 and December 31, 2012 you recorded material downward revisions to your proved undeveloped reserves (PUDs). Regarding these revisions tell us the following:

•
When the underlying volumes were originally booked as PUDs;


United States Securities and Exchange Commission
Division of Corporation Finance
January 29, 2016
Page 4

•
The year they were scheduled for development at the time of initial booking;
•
Any subsequent revisions to the initial development date, along with reasons for any such subsequent revisions; and,
•
The specific facts and circumstances that led to your decision to remove the PUD volumes.
Response:
Since 2012, the Wattenberg Field resource play has had significant horizontal development by us and other crude oil and natural gas exploration and production companies. Increased well density tests, new and improved completion technologies and further statistical industry data in the field have supported booking proven and probable undeveloped reserves at an increasing well density. To provide support for the required certainty to increase the well density of PUD reserves, we have focused our near-term development plans on drilling a significant number of unproven locations. The focus on downspacing testing, including the development of these unproven locations, subsequently reduced the annual conversion rate for proved undeveloped reserves in 2012, 2013 and 2014 below the 20% conversion rate implied by the five-year rule. The success of downspacing results in 2013 and 2014 in the Wattenberg Field provided support for increasing well density in our PUD reserves. In 2012, we had booked four wells per “section” (640 acres) equivalent in the Niobrara formation, in 2013 we booked six wells per section equivalent and in 2014 we booked the majority of our planned wells at eight wells per section equivalent. Our reserve report as of December 31, 2015 (which has yet to be published) is predicated upon booking 16 wells per section equivalent spacing in the Niobrara formation. Our 2015 drilling program in the Wattenberg Field focused on drilling primarily proven downspaced locations, which we expected to result in a PUD conversion rate of approximately 16%, as disclosed on page 90 of the Annual Report. Our actual conversion rate for 2015 was 17%.

Regarding inquires of the Staff in the bullets shown above:

•
Comment #3, First Bullet - As detailed in the tables shown above in our response to Comment #2, the years when the underlying volumes were originally booked as PUDs were as follows:

▪
The underlying volumes associated with the downward revisions to our PUD reserves of 40,321 MBoe during the year ended December 31, 2012 in Table 1 were originally booked during the years ended December 31, 2009, 2010 and 2011.

▪
The underlying volumes associated with the downward revisions to our PUD reserves of 39,729 MBoe during the year ended December 31, 2013 in Table 2 were originally booked during the years ended December 31, 2010, 2011 and 2012.

▪
The underlying volumes associated with the downward revisions to our PUD reserves of 41,998 MBoe as of December 31, 2014 in Table 3 were originally booked during the years ended December 31, 2011, 2012 and 2013.

•
Comment #3, Second Bullet - The years for scheduled development of downward revisions to our PUD reserves during the year ended 2012, 2013 and 2014 were as follows:

▪
Underlying volumes detailed in Table 1 shown above in our response to Comment #2 originally booked as PUD reserves at December 31, 2009 were initially scheduled to be developed in 2010, 2011, 2012, 2013 and 2014. Underlying volumes originally booked as PUD reserves at December 31, 2010 were initially scheduled to be developed in 2014 and 2015. Underlying volumes originally booked as PUD reserves at December 31, 2011 were initially scheduled to be developed in 2013, 2014, 2015 and 2016.



United States Securities and Exchange Commission
Division of Corporation Finance
January 29, 2016
Page 5

▪
Underlying volumes detailed in Table 2 shown above in our response to Comment #2 originally booked as PUD reserves at December 31, 2010 were initially scheduled to be developed in 2012, 2013 and 2014. Underlying volumes originally booked as PUD reserves at December 31, 2011 were initially scheduled to be developed in 2013, 2014 and 2015. Underlying volumes originally booked as PUD reserves at December 31, 2012 were initially scheduled to be developed in 2013, 2014, 2015, 2016 and 2017.

▪
Underlying volumes detailed in Table 3 shown above in our response to Comment #2 originally booked as PUD reserves at December 31, 2011 were initially scheduled to be developed in 2013, 2014 and 2015. Underlying volumes originally booked as PUD reserves at December 31, 2012 were initially scheduled to be developed in 2014, 2015 and 2016. Underlying volumes originally booked as PUD reserves at December 31, 2013 were initially scheduled to be developed in 2014, 2015, 2016, 2017 and 2018.

•
Comment #3, Third and Fourth Bullets - Overall, as we have provided the Staff in the tables shown above in our response to Comment #2, a further breakdown of our previously-stated “revisions of previous estimates.” Generally, the categories shown above consist of the following types of revisions and the specific facts and circumstances that led to our decision to remove PUD reserve volumes were as follows:

▪
Revisions from Changes in Development Plans: These types of changes occur as a result of significant changes in corporate strategy, commodity price outlook, drilling technology (i.e., downspacing, converting from vertical to horizontal, etc.) and/or available capital.

▪
Revisions due to Pricing, Updated Interests and Expenses: These types of changes occur upon the increasing or decreasing of the wells’ expected lives and the increased or decreased reserve values due to changes in the SEC commodity pricing used in our reserve report from year to year, updating our working interest due to parties electing to non-consent or title failures to wells to be drilled and/or an increase or decrease to the potential production from a well due to the well’s life being increased or decreased due to changes in our expected lease operating costs.

▪
Revisions due to Type Curve Adjustments and Other Factors: These types of changes are primarily a result of revisions to our type curves as a result of our ongoing engineering analysis of production data.

Above are general circumstances that lead to changes to each category within our revisions to previous estimates. The following are more specific factors that led to the subsequent revisions to the initial development dates, and reasons for such subsequent revisions, for each of the years ended December 31, 2012, 2013 and 2014:

▪
Revisions included in reserve report dated December 31, 2012: We had negative revisions as a result of our development plan changes of 38,290 Mboe as shown in Table 1. The factors that primarily led to these changes are as follows:

•
Merit Acquisition - We acquired nearly 30,000 acres in the Wattenberg Field, bringing our total in the field to nearly 100,000 acres. As a result, we added 109 new Merit-related drilling locations to our development plan as we saw some of them as more economic than our previously recorded Wattenberg Field locations. As such, it pushed some of the previously-booked locations beyond our five-year development plan and, therefore, the related reserves were moved back into our probable reserve category.



United States Securities and Exchange Commission
Division of Corporation Finance
January 29, 2016
Page 6

•
Converting Our Drilling Program from Primarily a Vertical Drilling Program to Primarily a Horizontal Drilling Program - As we gathered data to support our technical certainty around horizontal development, we removed vertical PUD locations and replaced them with new horizontal PUD locations. As a result, we showed the removal of vertical PUD reserves in the Revisions category and recorded the new horizontal PUD reserves in the Extension and Discoveries category.

•
Finally, we began an overall corporate strategy to change from a predominantly natural gas-focused company to a mix of liquids and natural gas, leaning more toward liquids. As a result, previously-recorded PUD, mainly natural gas, reserves were removed from our development plan. We made this change as our corporate outlook for liquids pricing was more favorable than that of natural gas. Ultimately, this led to numerous dispositions of assets, as shown in our sales of our dry gas assets located within the Piceance Basin and Northeastern Colorado during the first half of 2013.

▪
Revisions included in reserve report dated December 31, 2013: We had negative revisions as a result of our development plan changes of 48,886 MBoe as shown in Table 2. The factors that primarily led to these changes are as follows:

•
We increased our proven well density from four wells per section to six wells per section at the end of 2013. Therefore, some of the previous specific locations spaced at four wells per section were no longer included in the five-year development plan and, as a result of the increased density, were replaced with locations spaced at six wells per section. As such, we included the PUD reserves related to these removed well locations in the Revisions category and included the PUD reserves related to the new wells in the Extensions and Discoveries category.

•
Additionally, we had a stronger move to liquids-focused development in 2014, as shown by our 2014 budget including just $16 million of the total budget of $647 million for the drilling of dry gas Marcellus Shale assets. As such, we removed some formerly-recorded Marcellus Shale PUD reserves

•
We allocated more capital to our liquid-rich Utica Shale assets which, at the time, did not have significant PUD reserves as it was an emerging play. This limited the remaining capital to be spent in the Wattenberg Field and, therefore, slightly changed our development plans.

•
During the spring and summer of 2013, there was an unforeseen increase in line pressures which adversely impacted the gathering system of our primary third-party midstream provider in the Wattenberg Field. Due to these impacts, the immediate drilling schedule was revised to develop in areas which were considered to be less affected by the high line pressures. This resulted in the development date for some of the previously booked locations being pushed back beyond the requirements of the five-year rule and, therefore, these locations were moved back into our probable reserve category.

▪
Revisions included in reserve report dated December 31, 2014: We had negative revisions as a result of our development plan changes of 53,714 MBoe as shown in Table 3. The factors that primarily led to these changes are as follows:

•
Our year-end 2014 development plan significantly changed the locations within the Wattenberg Field which our operations teams wanted to develop. Throughout 2013 and 2014, we gathered a tremendous amount of information about the Wattenberg Field from our successful horizontal drilling program. However, as oil prices fell, we subsequently shifted our focus to the areas generating the highest internal rates of return and had a more balanced mix of natural gas, natural


United States Securities and Exchange Commission
Division of Corporation Finance
January 29, 2016
Page 7

gas liquids and oil, and thus a portion of previously-recorded PUD reserves moved beyond our five-year development plan and back into the probable category.

•
Other changes to the development plan included additional downspacing in the Wattenberg Field as described earlier (i.e., moving from six wells per section to eight wells per section) with primary focus on the Wattenberg Field, limited focus on the Utica Shale and the sale of our dry gas Marcellus Shale assets.

We propose that when discussing year over year changes to our reserves in our Annual Report on Form 10-K for the year ended December 31, 2015 and future years, in addition to continuing to disclose our expected conversion rates, we will also add any additional information necessary to assist users of the information in understanding substantial changes to our development plans when we have significant revisions to previous estimates.

4.
For the years ended December 31, 2014, December 31, 2013, December 31, 2012 and December 31, 2011, tell us the number of PUD locations scheduled to be drilled in the following year per the year-end reserve report and the number of wells actually drilled. For example, tell us the number of PUD locations scheduled to be drilled during 2012 according to the development schedule underlying your December 31, 2011 reserve report and the number of PUD locations actually drilled during 2012.
Response:
The following table details the number of PUD locations scheduled to be drilled and actually drilled in the following year per the year-end reserve reports for the years ended December 31, 2011, 2012, 2013 and 2014. Additionally, we have provided the total number of wells actually drilled in the following year per the year-end reserve reports for the years ended December 31, 2011, 2012, 2013 and 2014.

Reserve Report as of December 31,
 
PUDs Scheduled to be Drilled in the Year Following the Report Year
 
PUDs Actually Drilled in the Year Following the Report Year
 
Total Number of Wells Actually Drilled in the Year Following the Report Year
 
 
 
 
 
 
 
2011
 
72
 
39
 
83
2012
 
60
 
15
 
118
2013
 
65
 
57
 
171
2014
 
104
 
111
 
198


For the years ended December 31, 2011 and 2012, the difference in actual PUDs drilled versus scheduled are the result of circumstances that were not foreseen at the time related reserve reports were prepared and which more fully addressed in our responses to Comment #3. Refer to our responses to Comment #3, Third and Fourth Bullets above for more expansive discussions of these factors and the related impact on our PUD reserves.

The following are further descriptions of these circumstances:

•
For the reserve report as of December 31, 2011, the difference of 33 scheduled locations largely resulted from 17 of the scheduled locations being sold as part of divestiture of Permian Basin oil and gas properties, which closed in the first quarter of 2012. The difference was further impacted by our move to drilling


United States Securities and Exchange Commission
Division of Corporation Finance
January 29, 2016
Page 8

primarily horizontal wells rather than primarily vertical wells and our emphasis on drilling liquid-rich locations as opposed to dry gas locations

•
For the reserve report as of December 31, 2012, the difference of 45 locations largely resulted from a significant, unforeseen increase in line pressures adversely impacting the gathering system of our primary third-party midstream provider in the Wattenberg Field during the spring and summer months of 2013. The increased line pressures resulted in curtailed production of natural gas throughout the field, which led us to alter our 2013 drilling plans by shifting drilling activities to areas that were relatively less affected by the line pressure issues. The difference was further impacted by increased well density and a move to develop our Utica Shale assets, which did not have significant PUD reserves at the time.

We propose that in future Annual Reports on Form 10-K, if our actual conversion rate falls significantly short of our previously-disclosed expected conversion rate, we will provide a detailed discussion of the factors contributing to such shortfall.

The Company hereby acknowledges a) that the Company is responsible for the adequacy and accuracy of the disclosure in the filing, b) that staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing, and c) that the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.
Please contact the undersigned with any questions at 303.860.5800.
Sincerely,
 
 
 
/s/ Gysle R. Shellum
 
 
 
Gysle R. Shellum
 
Chief Financial Officer
 




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