Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 
FORM 8-K
 
 

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): November 5, 2018
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PDC Energy, Inc.
(Exact name of registrant as specified in its charter)


Delaware
 
001-37419
 
95-2636730
(State or other jurisdiction of
 
(Commission
 
(I.R.S. Employer
incorporation or organization)
 
File Number)
 
Identification Number)

1775 Sherman Street, Suite 3000
Denver, Colorado 80203
(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (303) 860-5800


Not Applicable
(Former name or former address, if changed since last report)


Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))







Item 2.02 Results of Operations and Financial Condition.

The following information is furnished pursuant to Item 2.02.
 
On November 5, 2018, PDC Energy, Inc. issued a press release announcing its operating and financial results for the fiscal quarter ended September 30, 2018. A copy of the press release is furnished as Exhibit 99.1 and incorporated by reference herein.

The information in this Current Report on Form 8-K, including the exhibit hereto, is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits
Exhibit No.
 
Description
 
 
 
99.1
 
 






SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Date: November 5, 2018
PDC ENERGY, INC.

By:
/s/ Daniel W. Amidon
 
Daniel W. Amidon
 
Senior Vice President, General Counsel and Secretary



Exhibit


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November 5, 2018
PDC Energy Announces 2018 Third Quarter Operating and Financial Results Including Total Production of 10.1 Million Barrels of Oil Equivalent
DENVER, CO, November 5, 2018: PDC Energy, Inc. ("PDC" or the "Company") (NASDAQ: PDCE) today reported its 2018 third quarter operating and financial results.
Third Quarter 2018 Highlights
Production of 10.1 million barrels of oil equivalent (“MMBoe”), or approximately 110,000 barrels of oil equivalent (“Boe”) per day, representing a year-over-year increase of 21 percent from Wattenberg and Delaware basin operations.
Oil production of 4.3 million barrels (“MMBbls”), a 27 percent increase year-over-year from Wattenberg and Delaware basin operations.
Delaware Basin oil price realizations equal to approximately 94 percent of NYMEX average pricing.

CEO Commentary

President and Chief Executive Officer, Bart Brookman commented, “The third quarter offered several positives, including a glimpse of our multi-basin strategy delivering the results and efficiencies needed to propel us through the next several years. Our Wattenberg operating performance is beginning to improve, as production and costs are both trending in the right direction; however, our production continues to be curtailed by the shortfall in midstream capacity in the basin. In the Delaware, our Grizzly Bear downspacing test has moved PDC one-step closer to unlocking the optimal approach to maximizing value through full-field development. We are excited by the knowledge gained through this test and anxiously await the additional downspacing tests currently planned in 2019.”

Operations Update


Page | 1



Production for the third quarter of 2018 was 10.1 MMBoe, representing year-over-year increase of 21 percent from Wattenberg and Delaware basin operations. Daily production of approximately 110,000 Boe represents sequential growth of approximately six percent compared to the second quarter of 2018. Oil production of approximately 4.3 MMBbls represents nearly 43 percent of total production and an increase of 27 percent from Wattenberg and Delaware basin operations compared to the third quarter of 2017 and nine percent from the second quarter of 2018. The Company’s capital investment in its oil and natural gas properties, as well as other capital expenditures, before the change in accounts payable, was approximately $273 million.

In Wattenberg, the Company spud 43 wells and turned-in-line 22 wells in the third quarter. In August 2018, the Company’s primary midstream service provider increased its processing capacity, resulting in modest improvements to line pressures in the Core Wattenberg. Despite a slightly improved operating environment, ongoing system optimization and unplanned facility downtime continued to constrain certain PDC production in the third quarter beyond internal projections. Despite these challenges, PDC grew Wattenberg production by approximately seven percent compared to the second quarter of 2018 to an estimated 84,000 Boe per day.

In the Delaware basin, the Company spud eight wells and turned-in-line ten wells, consisting of one Central area well, the eight-well Grizzly Bear pad in its Block 4 area and an Eastern area well located outside of Block 4. The Grizzly Bear pad includes six Wolfcamp A wells on a half-section, testing twelve wells per-section equivalent, a Wolfcamp B well and a Wolfcamp C well. The Wolfcamp A wells are currently averaging approximately 75 percent crude oil and are showing minimal signs of communication through various choke management tests and casing pressure assessments. Through initial flowback, the Wolfcamp C well has yet to reach the Company’s internal production expectations despite exceeding expectations in terms of percent oil at approximately 60 percent of total production. All eight wells were turned-in-line late in the third quarter and have shown production performance consistent with expectations for the lower-GOR portion of Block 4.

Crude Oil and Natural Gas Production, Sales and Operating Cost Data

Crude oil, natural gas and natural gas liquids (“NGLs”) sales, excluding net settlements on derivatives, increased 60 percent to $372.4 million in the third quarter of 2018, compared to $232.7 million in the third quarter of 2017.  The increase in sales was due to the aforementioned increase in total production and an increase in the average sales price per Boe, excluding net settlements on derivatives, of 35 percent to $36.88 in the third quarter of 2018 from $27.35 in the comparable 2017 period.  Including the impact of net settlements on derivatives, combined revenues increased 34 percent between periods, to $324.3 million from $242.3 million.

The following table provides production by area, and weighted-average sales price for the three and nine months ended September 30, 2018 and 2017, excluding net settlements on derivatives:


Page | 2






 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
Percent Change
 
2018
 
2017
 
Percent Change
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
3,254

 
2,943

 
10.6
 %
 
9,076

 
7,883

 
15.1
 %
Delaware Basin
1,042

 
436

 
139.0
 %
 
2,918

 
1,075

 
171.4
 %
Utica Shale

 
60

 
(100.0
)%
 
46

 
226

 
(79.6
)%
Total
4,296

 
3,439

 
24.9
 %
 
12,040

 
9,184

 
31.1
 %
 
 
 
 
 
 
 
 
 
 
 
 
Weighted-Average Sales Price
$
66.27

 
$
45.66

 
45.1
 %
 
$
63.43

 
$
46.69

 
35.9
 %
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas (MMcf)
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
16,808

 
15,788

 
6.5
 %
 
48,169

 
44,694

 
7.8
 %
Delaware Basin
4,957

 
2,781

 
78.2
 %
 
13,457

 
6,052

 
122.4
 %
Utica Shale

 
501

 
(100.0
)%
 
414

 
1,691

 
(75.5
)%
Total
21,765

 
19,070

 
14.1
 %
 
62,040

 
52,437

 
18.3
 %
 
 
 
 
 
 
 
 
 
 
 
 
Weighted-Average Sales Price
$
1.60

 
$
2.17

 
(26.3
)%
 
$
1.67

 
$
2.23

 
(25.1
)%
 
 
 
 
 
 
 
 
 
 
 
 
NGLs (MBbls)
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
1,643

 
1,564

 
5.1
 %
 
4,616

 
4,473

 
3.2
 %
Delaware Basin
534

 
282

 
89.4
 %
 
1,360

 
625

 
117.6
 %
Utica Shale

 
46

 
(100.0
)%
 
34

 
151

 
(77.5
)%
Total
2,177

 
1,892

 
15.1
 %
 
6,010

 
5,249

 
14.5
 %
 
 
 
 
 
 
 
 
 
 
 
 
Weighted-Average Sales Price
$
24.35

 
$
18.11

 
34.5
 %
 
$
22.71

 
$
17.24

 
31.7
 %
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil equivalent (MBoe)
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
7,698

 
7,138

 
7.8
 %
 
21,721

 
19,805

 
9.7
 %
Delaware Basin
2,402

 
1,182

 
103.2
 %
 
6,520

 
2,709

 
140.7
 %
Utica Shale

 
189

 
(100.0
)%
 
149

 
658

 
(77.4
)%
Total
10,100

 
8,509

 
18.7
 %
 
28,390

 
23,172

 
22.5
 %
 
 
 
 
 
 
 
 
 
 
 
 
Weighted-Average Sales Price
$
36.88

 
$
27.35

 
34.8
 %
 
$
35.35

 
$
27.45

 
28.8
 %

Production costs for the third quarter of 2018, which include lease operating expenses (“LOE”), production taxes and transportation, gathering and processing expenses (“TGP”), were $66.2 million, or $6.55 per Boe, compared to $50.7 million, or $5.95 per Boe, for the comparable 2017 period. 

Wattenberg LOE per Boe in the third quarter of 2018 was $3.01 compared to $2.49 in the third quarter of 2017 and $3.29 in the second quarter of 2018. The sequential decrease in Wattenberg LOE per Boe in 2018 was primarily due to increased production volumes related to the aforementioned midstream processing expansion. In the Delaware Basin, LOE per Boe in the third quarter of 2018 was $4.09 compared to $6.07 per Boe in the third quarter of 2017

Page | 3



and $3.92 in the second quarter of 2018. The sequential increase in Delaware basin LOE in 2018 was primarily due to minimal production contribution from the ten wells turned-in-line late in the third quarter.

The following table provides the components of production costs for the three and nine months ended September 30, 2018 and 2017 in millions of dollars and on a per Boe basis:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
Lease operating expenses
$
33.0

 
$
25.4

 
$
94.9

 
$
65.2

Production taxes
24.0

 
15.5

 
66.8

 
43.0

Transportation, gathering and processing expenses
9.2

 
9.8

 
25.5

 
22.2

Total
$
66.2

 
$
50.7

 
$
187.2

 
$
130.4



 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
Lease operating expenses per Boe
$
3.27

 
$
2.98

 
$
3.34

 
$
2.81

Production taxes per Boe
2.37

 
1.82

 
2.35

 
1.85

Transportation, gathering and processing expenses per Boe
0.91

 
1.15

 
0.90

 
0.96

Total per Boe
$
6.55

 
$
5.95

 
$
6.59

 
$
5.62



Financial Results

Net loss for the third quarter of 2018 was $3.4 million, or $0.05 per diluted share, compared to net loss of $292.5 million, or $4.44 per diluted share, for the comparable period of 2017. The year-over-year difference was primarily attributable to the $97.5 million difference in total revenues between periods and impairments recorded in the third quarter of 2017 of both unproved properties and goodwill totaling $327.9 million.

Adjusted net income, a non-U.S. GAAP measure defined below, was $31.8 million, or $0.48 per diluted share in the third quarter of 2018 compared to adjusted net loss of $253.9 million, or $3.85 per diluted share for the comparable period of 2017.

Net cash from operating activities was $197.0 million in the third quarter of 2018, compared to $148.2 million in the comparable 2017 period.  Adjusted cash flows from operations, a non-U.S. GAAP financial measure defined below, were $201.1 million in the third quarter of 2018, compared to $150.9 million in the comparable 2017 period.


Page | 4



General and administrative expense (“G&A”) was $48.2 million, or $4.78 per Boe for the third quarter of 2018 compared to $29.3 million or $3.44 per Boe in the third quarter of 2017. The year-over-year difference is primarily due to an increase of approximately $8 million in legal related costs. Excluding these costs would result in G&A per Boe of $3.99 in the third quarter of 2018. Additional increases in G&A per Boe are attributable to increases in payroll and employee benefits due to total employee headcount, professional services and expenses related to government relations.

2018 Capital Investment Outlook and Financial Guidance

The Company has seen modest improvements to its Wattenberg production volumes and system-wide line pressures while maintaining its expected allocation of total system capacity from its primary midstream service provider in the Wattenberg Field. However, due to the pace of ongoing third party midstream system optimization in Wattenberg and both planned and unplanned downtime in the third and fourth quarter, the Company now expects full-year 2018 production to be at the low end of its production guidance range, or approximately 40 MMBoe. As a result of these midstream constraints negatively impacting production throughout the second half of the year, the Company expects its operating expenses per Boe to be at or slightly above the high-end of the provided guidance ranges in 2018. The Company does not currently anticipate these midstream constraints to materially impact its 2019 production growth outlook of 25 to 35 percent.

The Company expects its 2018 capital investment for crude oil and natural gas properties to be in the middle of its previously disclosed guidance range.

The following table summarizes the Company’s 2018 financial guidance:


Page | 5



 
Low
High
Production (MMBoe)
40.0

42.0

Capital Investment in Crude Oil and Natural Gas Properties (millions)
$
950

$
985

 
 
 
Operating Expenses
Lease operating expense ($/Boe)
$
3.00

$
3.15

Transportation, gathering and processing expenses ($/Boe)
$
0.80

$
0.90

Production taxes (% of Crude oil, natural gas & NGL sales)
6
%
8
%
General and administrative expense ($/Boe)
$
3.40

$
3.70

Estimated Price Realizations (% of NYMEX) (excludes TGP)
Crude oil
91%
95%
Natural gas
55%
60%
NGLs
30%
35%

*G&A per Boe range excludes the previously described legal related costs of approximately $8 million in the third quarter. Inclusion of this amount would result in G&A per Boe exceeding the top-end of the provided guidance range by approximately $0.25 per Boe.

Non-GAAP Financial Measures

PDC uses "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that the Company uses may not be comparable to similarly titled measures reported by other companies. Also, in the future, PDC may disclose different non-U.S. GAAP financial measures in order to help investors more meaningfully evaluate and compare future results of operations to previously reported results of operations. PDC strongly encourages investors to review its financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

The following tables provide reconciliations of adjusted cash flows from operations, adjusted net income (loss) and adjusted EBITDAX to their most comparable U.S. GAAP measures (in millions, except per share data):






Page | 6





Adjusted Cash Flows from Operations
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Adjusted cash flows from operations:
 
 
 
 
 
 
 
Net cash from operating activities
$
197.0

 
$
148.2

 
$
577.8

 
$
420.7

Changes in assets and liabilities
4.1

 
2.7

 
(2.5
)
 
(13.1
)
Adjusted cash flows from operations
$
201.1

 
$
150.9

 
$
575.3

 
$
407.6


Adjusted Net Income (Loss)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Adjusted net income (loss):
 
 
 
 
 
 
 
Net loss
$
(3.4
)
 
$
(292.5
)
 
$
(176.8
)
 
$
(205.1
)
(Gain) loss on commodity derivative instruments
94.4

 
52.2

 
257.8

 
(86.5
)
Net settlements on commodity derivative instruments
(48.1
)
 
9.6

 
(90.5
)
 
22.2

Tax effect of above adjustments
(11.1
)
 
(23.2
)
 
(40.1
)
 
24.0

Adjusted net income (loss)
$
31.8

 
$
(253.9
)
 
$
(49.6
)
 
$
(245.4
)
Weighted-average diluted shares outstanding
66.1

 
65.9

 
66.0

 
65.8

Adjusted diluted earnings per share
$
0.48

 
$
(3.85
)
 
$
(0.75
)
 
$
(3.73
)


Page | 7



Adjusted EBITDAX
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Net loss to adjusted EBITDAX:
 
 
 
 
 
 
 
Net loss
$
(3.4
)
 
$
(292.5
)
 
$
(176.8
)
 
$
(205.1
)
(Gain) loss on commodity derivative instruments
94.4

 
52.2

 
257.8

 
(86.5
)
Net settlements on commodity derivative instruments
(48.1
)
 
9.6

 
(90.5
)
 
22.2

Non-cash stock-based compensation
5.6

 
4.8

 
16.4

 
14.6

Interest expense, net
17.4

 
18.8

 
52.2

 
56.9

Income tax expense (benefit)
(3.9
)
 
(122.4
)
 
(53.8
)
 
(71.5
)
Impairment of properties and equipment
1.5

 
252.7

 
194.2

 
282.5

Impairment of goodwill

 
75.1

 

 
75.1

Exploration, geologic and geophysical expense
1.0

 
41.9

 
4.6

 
43.9

Depreciation, depletion and amortization
147.5

 
125.2

 
410.0

 
360.6

Accretion of asset retirement obligations
1.2

 
1.5

 
3.8

 
4.9

Adjusted EBITDAX
$
213.2

 
$
166.9

 
$
617.9

 
$
497.6

 
 
 
 
 
 
 
 
Cash from operating activities to adjusted EBITDAX:
 
 
 
 
 
 
 
Net cash from operating activities
$
197.0

 
$
148.2

 
$
577.8

 
$
420.7

Interest expense, net
17.4

 
18.8

 
52.2

 
56.9

Amortization of debt discount and issuance costs
(3.1
)
 
(3.2
)
 
(9.5
)
 
(9.6
)
Gain (loss) on sale of properties and equipment
(2.1
)
 
0.1

 
(3.2
)
 
0.8

Exploration, geologic and geophysical expense
1.0

 
41.9

 
4.6

 
43.9

Exploratory dry hole costs

 
(41.2
)
 

 
(41.2
)
Other
(1.1
)
 
(0.4
)
 
(1.5
)
 
39.2

Changes in assets and liabilities
4.1

 
2.7

 
(2.5
)
 
(13.1
)
Adjusted EBITDAX
$
213.2

 
$
166.9

 
$
617.9

 
$
497.6





Page | 8



PDC ENERGY, INC.
Condensed Consolidated Statements of Operations
(unaudited, in thousands, except per share data)

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
Crude oil, natural gas and NGLs sales
$
372,439

 
$
232,733

 
$
1,003,597

 
$
636,027

Commodity price risk management gain (loss), net
(94,394
)
 
(52,178
)
 
(257,760
)
 
86,458

Other income
2,672

 
2,680

 
8,011

 
9,615

Total revenues
280,717

 
183,235

 
753,848

 
732,100

Costs, expenses and other
 
 
 
 
 
 
 
Lease operating expenses
33,046

 
25,353

 
94,942

 
65,170

Production taxes
23,984

 
15,516

 
66,757

 
42,957

Transportation, gathering and processing expenses
9,234

 
9,794

 
25,511

 
22,184

Exploration, geologic and geophysical expense
1,032

 
41,908

 
4,553

 
43,895

Impairment of properties and equipment
1,488

 
252,740

 
194,230

 
282,499

Impairment of goodwill

 
75,121

 

 
75,121

General and administrative expense
48,240

 
29,299

 
121,183

 
85,145

Depreciation, depletion and amortization
147,540

 
125,238

 
409,952

 
360,567

Accretion of asset retirement obligations
1,200

 
1,472

 
3,773

 
4,906

(Gain) loss on sale of properties and equipment
2,118

 
(62
)
 
3,199

 
(754
)
Provision for uncollectible note receivable

 

 

 
(40,203
)
Other expenses
2,711

 
2,947

 
8,187

 
10,365

Total costs, expenses and other
270,593

 
579,326

 
932,287

 
951,852

Income (loss) from operations
10,124

 
(396,091
)
 
(178,439
)
 
(219,752
)
Interest expense
(17,622
)
 
(19,275
)
 
(52,561
)
 
(58,359
)
Interest income
188

 
479

 
405

 
1,487

Loss before income taxes
(7,310
)
 
(414,887
)
 
(230,595
)
 
(276,624
)
Income tax benefit
3,876

 
122,350

 
53,765

 
71,483

Net loss
$
(3,434
)
 
$
(292,537
)
 
$
(176,830
)
 
$
(205,141
)
 
 
 
 
 
 
 
 
Earnings per share:
 
 
 
 
 
 
 
Basic
$
(0.05
)
 
$
(4.44
)
 
$
(2.68
)
 
$
(3.12
)
Diluted
$
(0.05
)
 
$
(4.44
)
 
$
(2.68
)
 
$
(3.12
)
 
 
 
 
 
 
 
 
Weighted-average common shares outstanding:
 
 
 
 
 
 
 
Basic
66,073

 
65,865

 
66,032

 
65,825

Diluted
66,073

 
65,865

 
66,032

 
65,825








Page | 9





PDC ENERGY, INC.
Condensed Consolidated Balance Sheets
(unaudited, in thousands, except share and per share data)

 
 
September 30, 2018
 
December 31, 2017
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
1,369

 
$
180,675

Accounts receivable, net
 
241,155

 
197,598

Fair value of derivatives
 
7,555

 
14,338

Prepaid expenses and other current assets
 
6,713

 
8,613

Total current assets
 
256,792

 
401,224

Properties and equipment, net
 
4,309,021

 
3,933,467

Assets held-for-sale, net
 

 
40,084

Fair value of derivatives
 
3,949

 

Other assets
 
31,462

 
45,116

Total Assets
 
$
4,601,224

 
$
4,419,891

 
 
 
 
 
Liabilities and Stockholders' Equity
 
 
 
 
Liabilities
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
251,081

 
$
150,067

Production tax liability
 
59,539

 
37,654

Fair value of derivatives
 
205,013

 
79,302

Funds held for distribution
 
104,259

 
95,811

Accrued interest payable
 
15,425

 
11,815

Other accrued expenses
 
39,260

 
42,987

Total current liabilities
 
674,577

 
417,636

Long-term debt
 
1,234,733

 
1,151,932

Deferred income taxes
 
138,963

 
191,992

Asset retirement obligations
 
72,707

 
71,006

Fair value of derivatives
 
61,013

 
22,343

Other liabilities
 
76,987

 
57,333

Total liabilities
 
2,258,980

 
1,912,242

 
 
 
 
 
Commitments and contingent liabilities
 
 
 
 
 
 
 
 
 
Stockholders' equity
 
 
 
 
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,136,427 and 65,955,080 issued as of September 30, 2018 and December 31, 2017, respectively
 
661

 
659

Additional paid-in capital
 
2,514,861

 
2,503,294

Retained earnings (deficit)
 
(170,126
)
 
6,704

Treasury shares - at cost, 62,265 and 55,927
as of September 30, 2018 and December 31, 2017, respectively
 
(3,152
)
 
(3,008
)
Total stockholders' equity
 
2,342,244

 
2,507,649

Total Liabilities and Stockholders' Equity
 
$
4,601,224

 
$
4,419,891

 
 
 
 
 

Page | 10



PDC ENERGY, INC.
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
Cash flows from operating activities:
 
 
 
 
 
 
 
 
Net loss
 
$
(3,434
)
 
$
(292,537
)
 
$
(176,830
)
 
$
(205,141
)
Adjustments to net loss to reconcile to net cash from operating activities:
 
 
 
 
 
 
 
 
Net change in fair value of unsettled commodity derivatives
 
46,298

 
61,763

 
167,218

 
(64,307
)
Depreciation, depletion and amortization
 
147,540

 
125,238

 
409,952

 
360,567

Impairment of properties and equipment
 
1,488

 
252,740

 
194,230

 
282,499

Impairment of goodwill
 

 
75,121

 

 
75,121

Exploratory dry hole costs
 

 
41,187

 

 
41,187

Provision for uncollectible notes receivable
 

 

 

 
(40,203
)
Accretion of asset retirement obligations
 
1,200

 
1,472

 
3,773

 
4,906

Non-cash stock-based compensation
 
5,578

 
4,761

 
16,357

 
14,587

(Gain) loss on sale of properties and equipment
 
2,118

 
(62
)
 
3,199

 
(754
)
Amortization of debt discount and issuance costs
 
3,082

 
3,229

 
9,454

 
9,628

Deferred income taxes
 
(2,848
)
 
(122,296
)
 
(53,029
)
 
(71,529
)
Other
 
51

 
316

 
1,025

 
986

Changes in assets and liabilities
 
(4,096
)
 
(2,727
)
 
2,485

 
13,105

Net cash from operating activities
 
196,977

 
148,205

 
577,834

 
420,652

Cash flows from investing activities:
 
 
 
 
 
 
 
 
Capital expenditures for development of crude oil and natural gas properties
 
(252,914
)
 
(194,444
)
 
(685,549
)
 
(528,850
)
Capital expenditures for other properties and equipment
 
(1,289
)
 
(1,441
)
 
(3,739
)
 
(3,740
)
Acquisition of crude oil and natural gas properties, including settlement adjustments
 
(520
)
 
(19,854
)
 
(181,572
)
 
(14,482
)
Proceeds from sale of properties and equipment
 
661

 
2,029

 
2,443

 
3,322

Proceeds from divestiture
 
4,470

 

 
43,493

 

Sale of promissory note
 

 

 

 
40,203

Restricted cash
 

 

 
1,249

 
(9,250
)
Sale of short-term investments
 

 

 

 
49,890

Purchases of short-term investments
 

 

 

 
(49,890
)
Net cash from investing activities
 
(249,592
)
 
(213,710
)
 
(823,675
)
 
(512,797
)
Cash flows from financing activities:
 
 
 
 
 
 
 
 
Proceeds from revolving credit facility
 
396,000

 

 
629,000

 

Repayment of revolving credit facility
 
(343,000
)
 

 
(554,000
)
 

Payment of debt issuance costs
 
(26
)
 

 
(4,086
)
 

Purchases of treasury stock
 
(206
)
 
(51
)
 
(4,700
)
 
(5,325
)
Other
 
(209
)
 
(306
)
 
(928
)
 
(951
)
Net cash from financing activities
 
52,559

 
(357
)
 
65,286

 
(6,276
)
Net change in cash, cash equivalents and restricted cash
 
(56
)
 
(65,862
)
 
(180,555
)
 
(98,421
)
Cash, cash equivalents and restricted cash, beginning of period
 
9,426

 
211,541

 
189,925

 
244,100

Cash, cash equivalents and restricted cash, end of period
 
$
9,370

 
$
145,679

 
$
9,370

 
$
145,679


Page | 11




Page |

Page |
2018 Third Quarter Teleconference and Webcast
The Company invites you to join Bart Brookman, President and Chief Executive Officer; Scott Meyers, Chief Financial Officer; Lance Lauck, Executive Vice President Corporate Development and Strategy; and Scott Reasoner, Chief Operating Officer, for a conference call on Tuesday, November 6, 2018 to discuss its 2018 third quarter results. The related slide presentation will be available on PDC’s website at www.pdce.com.
Conference Call and Webcast:
Date/Time: Tuesday, November 6, 2018, 11:00 a.m. ET
Webcast available at: www.pdce.com
Domestic (toll free): 877-312-5520
International: 253-237-1142
Conference ID: 6294656

Replay Numbers:
Domestic (toll free): 855-859-2056
International: 404-537-3406
Conference ID: 6294656

The replay of the call will be available for six months on PDC's website at www.pdce.com.

Upcoming Investor Presentations

PDC is scheduled to present at the Bank of America Energy Conference in Miami on Thursday, November 15, 2018. Webcast information will be posted to the Company’s website, www.pdce.com, prior to the start of each conference, along with any presentation materials.

About PDC Energy, Inc.

PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in Reeves and Culberson Counties, Texas. PDC’s operations are focused in the horizontal Niobrara and Codell plays in the Wattenberg Field and in the Wolfcamp zones in the Delaware Basin.



Page | 12



NOTE REGARDING FORWARD-LOOKING STATEMENTS

This press release contains forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 ("Securities Act"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; management of lease expiration issues; financial ratios and compliance with covenants in our revolving credit facility; impacts of certain accounting and tax changes; midstream capacity and related curtailments; impacts of Proposition 112 and other
Colorado political matters; ability to meet our volume commitments to midstream providers; ongoing compliance with our consent decree; reclassification of the Denver Metro/North Front Range NAA ozone classification to serious; and timing and adequacy of infrastructure projects of our midstream providers, including the impact of having a new plant come online during the third quarter of 2018.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or our industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

changes in worldwide production volumes and demand, including economic conditions that might impact demand and prices for the products we produce;
volatility of commodity prices for crude oil, natural gas and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices;
volatility and widening of differentials;
reductions in the borrowing base under our revolving credit facility;

Page | 13



impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement of those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;
declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments;
changes in estimates of proved reserves;
inaccuracy of reserve estimates and expected production rates;
potential for production decline rates from our wells being greater than expected;
timing and extent of our success in discovering, acquiring, developing and producing reserves;
availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;
timing and receipt of necessary regulatory permits;
risks incidental to the drilling and operation of crude oil and natural gas wells;
difficulties in integrating our operations as a result of any significant acquisitions and acreage exchanges;
increases or changes in costs and expenses;
availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells;
potential losses of acreage due to lease expirations or otherwise;
increases or adverse changes in construction and procurement costs associated with future build out of midstream-related assets;
future cash flows, liquidity and financial condition;
competition within the oil and gas industry;
availability and cost of capital;
our success in marketing crude oil, natural gas and NGLs;
effect of crude oil and natural gas derivative activities;
impact of environmental events, governmental and other third-party responses to such events and our ability to insure adequately against such events;
cost of pending or future litigation;
effect that acquisitions we may pursue have on our capital requirements;
our ability to retain or attract senior management and key technical employees; and
success of strategic plans, expectations and objectives for our future operations.

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those
under the heading "Risk Factors," made in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2017 filed with the U.S. Securities and Exchange Commission ("SEC") on February 27, 2018 and as amended on May 1, 2018 (the "2017 Form 10-K"), and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of

Page | 14



operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.


Contacts:    Michael Edwards
Senior Director Investor Relations
303-860-5820
michael.edwards@pdce.com

Kyle Sourk
Manager Investor Relations
303-318-6150
kyle.sourk@pdce.co

###


Page | 15