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): August 8, 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 August 8, 2018, PDC Energy, Inc. issued a press release announcing its operating and financial results for the fiscal quarter ended June 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: August 8, 2018
PDC ENERGY, INC.

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






EXHIBIT INDEX
Exhibit No.
 
Description
 
 
 
99.1
 



Exhibit


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August 8, 2018
PDC Energy Announces 2018 Second Quarter Operating and Financial Results Including Total Production of 9.4 Million Barrels of Oil Equivalent; Updates 2018 Production and Financial Guidance
DENVER, CO, August 8, 2018: PDC Energy, Inc. ("PDC" or the "Company") (NASDAQ: PDCE) today reported its 2018 second quarter operating and financial results, as well as updated its full-year 2018 production and financial guidance.
Second Quarter 2018 Highlights
Production of 9.4 million barrels of oil equivalent (“MMBoe”), or approximately 103,000 barrels of oil equivalent (“Boe”) per day, representing a year-over-year increase of 20 percent from Wattenberg and Delaware basin operations.
Oil production of 3.9 million barrels (“MMBbls”), a 25 percent increase year-over-year from Wattenberg and Delaware basin operations.
Delaware basin production averaged approximately 25,000 Boe per day, a sequential increase of approximately 20 percent from the first quarter of 2018.
Updated Full-Year 2018 Guidance Highlights
Increased midpoint of total production to 41 MMBoe with an updated range of 40 to 42 MMBoe, primarily as a result of Delaware basin outperformance.
Improved Wattenberg drilling and completion efficiencies resulting in an increase in 2018 estimated spuds and completion stages per well.
Anticipated capital investment of $950 to $985 million with an expected outspend of $75 to $100 million. The Company expects to generate free cash flow in the second half of 2018.


Page | 1



CEO Commentary

President and Chief Executive Officer, Bart Brookman commented, “Our second quarter results were a great testament to our long-term strategy of being a premier multi-basin operator. We’ve been dealt an incredibly difficult hand to play over the past year in terms of the Wattenberg midstream constraints. Our entire team, from pumpers to asset planners to our midstream team, have done a tremendous job of not only managing our production through these times, but also continuing to capture increased operational efficiencies. We are incredibly excited to be on the doorstep of truly unlocking the potential of our Core Wattenberg position with the recent start-up of DCP’s Plant 10.

Meanwhile, the strides made from our Delaware team have helped make up for our Wattenberg constraints. Consistent well results and consecutive quarters of outperformance have quickly led our Delaware production to account for approximately 25% of our corporate volumes. I’m extremely pleased with the team’s ability to improve our margins while managing through a challenging service cost and netback price environment.”

Operations Update

Production for the second quarter of 2018 was 9.4 MMBoe, representing year-over-year increase of 20 percent from Wattenberg and Delaware basin operations. Daily production of approximately 103,000 Boe represents sequential growth from Wattenberg and Delaware basin operations of approximately six percent compared to the first quarter of 2018. Oil production of approximately 3.9 MMBbls represents 42 percent of total production and a volumetric increase of 25 percent from the second quarter of 2017 and four percent from the first quarter of 2018. The Company’s capital investment in the development of its oil and natural gas properties, as well as other capital expenditures, before the change in accounts payable, was in line with internal expectations at approximately $260 million.

In the Delaware basin, the Company spud six wells and turned-in-line (“TIL”) five wells, consisting of two Central area wells and three Eastern area wells. Among the Eastern area TILs were two wells located in the Company’s Block 4 focus area, the Elkhead and Kenosha, which had peak 30-day IP rates averaging approximately 290 Boe per day per thousand feet and more than 60 percent crude oil. Year-to-date, the Company has seven Central area TILs averaging peak 30-day IP rates of approximately 220 Boe per day per thousand feet and 53 percent crude oil, both of which are above internal expectations. In June 2018, the Company sold initial crude oil volumes under its previously announced five and half year firm transportation agreement to the Gulf Coast. Average price realizations for all Delaware oil volumes in June, including volumes not covered by the new agreement, were approximately 92 percent of NYMEX.

In Wattenberg, the Company spud 43 wells and TIL 48 wells. The Company faced difficult operating conditions throughout the second quarter as a lack of spare gas processing capacity, high line pressures, planned and unplanned

Page | 2



gas processing downtime and hotter than average temperatures negatively impacted production volumes and operating costs. With the recent start-up of additional processing capacity in the field, the Company anticipates production in the second half of 2018 to materially benefit from an expected field-wide reduction in line pressures.

Oil and Gas Production, Sales and Operating Cost Data

Crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, increased 53% to $325.9 million in the second quarter of 2018, compared to $213.6 million in the second quarter of 2017.  The increase in sales was due to the aforementioned increase in total production and an increase in the sales price per Boe, excluding net settlements on derivatives, of 30% to $34.74 in the second quarter of 2018 from $26.65 in the comparable 2017 period.  Including the impact of net settlements on derivatives, combined revenues decreased 23% between periods, to $212.5 million from $275.2 million.

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




Page | 3



 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
Percent Change
 
2018
 
2017
 
Percent Change
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
2,943

 
2,798

 
5.2
 %
 
5,823

 
4,940

 
17.9
 %
Delaware Basin
1,005

 
364

 
176.1
 %
 
1,876

 
639

 
193.6
 %
Utica Shale

 
75

 
(100.0
)%
 
46

 
166

 
(72.3
)%
Total
3,948

 
3,237

 
22.0
 %
 
7,745

 
5,745

 
34.8
 %
 
 
 
 
 
 
 
 
 
 
 
 
Weighted-Average Sales Price
$
63.99

 
$
45.97

 
39.2
 %
 
$
61.85

 
$
47.31

 
30.7
 %
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas (MMcf)
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
15,836

 
15,192

 
4.2
 %
 
31,360

 
28,906

 
8.5
 %
Delaware Basin
4,851

 
2,025

 
139.6
 %
 
8,500

 
3,271

 
159.9
 %
Utica Shale

 
566

 
(100.0
)%
 
414

 
1,190

 
(65.2
)%
Total
20,687

 
17,783

 
16.3
 %
 
40,274

 
33,367

 
20.7
 %
 
 
 
 
 
 
 
 
 
 
 
 
Weighted-Average Sales Price
$
1.46

 
$
2.16

 
(32.4
)%
 
$
1.71

 
$
2.26

 
(24.3
)%
 
 
 
 
 
 
 
 
 
 
 
 
NGLs (MBbls)
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
1,544

 
1,551

 
(0.5
)%
 
2,973

 
2,909

 
2.2
 %
Delaware Basin
443

 
212

 
109.0
 %
 
826

 
343

 
140.8
 %
Utica Shale

 
51

 
(100.0
)%
 
34

 
105

 
(67.6
)%
Total
1,987

 
1,814

 
9.5
 %
 
3,833

 
3,357

 
14.2
 %
 
 
 
 
 
 
 
 
 
 
 
 
Weighted-Average Sales Price
$
21.76

 
$
14.59

 
49.1
 %
 
$
21.78

 
$
16.75

 
30.0
 %
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil equivalent (MBoe)
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
7,126

 
6,882

 
3.5
 %
 
14,023

 
12,667

 
10.7
 %
Delaware Basin
2,256

 
914

 
147.0
 %
 
4,118

 
1,527

 
169.6
 %
Utica Shale

 
219

 
(100.0
)%
 
149

 
469

 
(68.2
)%
Total
9,382

 
8,015

 
17.1
 %
 
18,290

 
14,663

 
24.7
 %
 
 
 
 
 
 
 
 
 
 
 
 
Weighted-Average Sales Price
$
34.74

 
$
26.65

 
30.4
 %
 
$
34.51

 
$
27.50

 
25.5
 %

Production costs for the second quarter of 2018, which include lease operating expenses (“LOE”), production taxes and transportation, gathering and processing expenses (“TGP”), were $63.9 million, or $6.81 per Boe, compared to $41.5 million, or $5.19 per Boe, for the comparable 2017 period.  Wattenberg LOE per Boe in the second quarter of 2018 was $3.29 compared to $2.22 in the second quarter of 2017 and $3.02 in the first quarter of 2018. The increase in LOE per Boe between periods is primarily due to the aforementioned midstream related operating conditions in Wattenberg negatively impacting both operating costs and production volumes. In the Delaware basin, increased production volumes as well as transporting effectively all produced water via pipe drove material improvements in LOE per Boe to $3.92 in the second quarter of 2018 compared to $4.88 in the comparable 2017 period and $4.44 in the first quarter of 2018.


Page | 4



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


 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
Lease operating expenses
$
32.3

 
$
20.0

 
$
61.9

 
$
39.8

Production taxes
22.6

 
15.0

 
42.8

 
27.4

Transportation, gathering and processing expenses
9.0

 
6.5

 
16.3

 
12.4

Total
$
63.9

 
$
41.5

 
$
121.0

 
$
79.6



 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
Lease operating expenses per Boe
$
3.44

 
$
2.50

 
$
3.38

 
$
2.72

Production taxes per Boe
2.41

 
1.88

 
2.34

 
1.87

Transportation, gathering and processing expenses per Boe
0.96

 
0.81

 
0.89

 
0.84

Total per Boe
$
6.81

 
$
5.19

 
$
6.61

 
$
5.43



Financial Results

Net loss for the second quarter of 2018 was $160.3 million, or $2.43 per diluted share, compared to net income of $41.3 million, or $0.62 per diluted share, for the comparable period of 2017. The year-over-year difference was primarily attributable to a $112.3 million increase in crude oil, natural gas and NGLs sales being offset by $174.1 million difference in commodity price risk management between periods. Additionally, as a result of widening gas differentials, increased well costs and the timing of lease expirations, the Company recorded an impairment of $159.5 million to select higher-GOR, non-focus area acreage. This impairment is not expected to impact the Company’s estimated focus area drilling inventory of approximately 450 mid-reach lateral equivalent locations.

Adjusted net loss, a non-GAAP measure defined below, was $84.5 million, or $1.28 per diluted share in the second quarter of 2018 compared to adjusted net income of $12.5 million, or $0.19 per diluted share for the comparable period of 2017. Excluding the aforementioned impairment expense and related tax impacts would have led to an adjusted net income of $36.8 million, or $0.56 per diluted share in the second quarter of 2018.


Page | 5



Net cash from operating activities was $175.7 million in the second quarter of 2018, compared to $132.9 million in the comparable 2017 period.  Adjusted cash flows from operations, a non-GAAP financial measure defined below, were $199.3 million in the second quarter of 2018, compared to $142.9 million in the comparable 2017 period.

2018 Updated Capital Investment Outlook and Financial Guidance

The Company increased its full-year 2018 production range to 40 to 42 MMBoe. The one MMBoe increase to the mid-point of the range compared to that of prior guidance is largely driven by Delaware basin outperformance. The Company increased its expected December 2018 exit rate to be approximately 135,000 Boe per day. As with the Company’s previous guidance, the potential positive impact from flush production associated with the recent midstream processing expansions in the Wattenberg Field is not included. For the full-year, the Company reaffirms its production mix ranges of 42-45% crude oil, 19-22% NGLs and 32-35% natural gas.

In Wattenberg, the Company now projects to spud between 150 to 165 wells in 2018, an increase from the previous range of 135 to 150, due to drilling efficiency gains realized through the first half of the year. Additionally, as a result of prior acreage trades leading to a more consolidated position, the Company has been able to modify its drilling and completion techniques to more effectively contact and stimulate the heels and toes of its laterals. This has led to an increase of approximately ten percent in anticipated completion stages per well throughout 2018. The Company expects the cost of additional stages, when combined with modest service cost inflation, and partially offset by faster drilling, to increase its Wattenberg per well costs in the second half of 2018 to between $3 and $5 million, depending on lateral length.

In the Delaware basin, the Company expects to spud and TIL 25 to 30 wells in 2018. In an effort to test the impact to production and reserves of various completion designs, as well as to manage well costs, the Company anticipates using approximately 25% fewer completion stages than in its original budget. As a result of service cost inflation, specifically due to a tight labor market and increased steel costs, the Company anticipates its Delaware basin well costs to increase approximately $1 million per well, to $10 and $15 million, depending on lateral length and target zone.

The Company now expects to invest between $950 and $985 million in 2018 as a result of the efficiency gains and updated well costs described above. For the full-year, the Company anticipates its capital investments will exceed its operating cash flows by approximately $75 to $100 million; however, the Company anticipates to generate free cash flow from its operations in the second half of 2018 and exit 2018 undrawn on its revolver.

The following table summarizes the updated 2018 financial guidance:


Page | 6



 
Low
High
Production (MMBoe)
40.0

42.0

Capital Expenditures (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%

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 | 7



Adjusted Cash Flows from Operations
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Adjusted cash flows from operations:
 
 
 
 
 
 
 
Net cash from operating activities
$
175.7

 
$
132.9

 
$
380.9

 
$
272.4

Changes in assets and liabilities
23.6

 
10.0

 
(6.6
)
 
(15.8
)
Adjusted cash flows from operations
$
199.3

 
$
142.9

 
$
374.3

 
$
256.6


Adjusted Net Income (Loss)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Adjusted net income (loss):
 
 
 
 
 
 
 
Net income (loss)
$
(160.3
)
 
$
41.2

 
$
(173.4
)
 
$
87.4

(Gain) loss on commodity derivative instruments
116.1

 
(57.9
)
 
163.4

 
(138.6
)
Net settlements on commodity derivative instruments
(16.4
)
 
12.0

 
(42.4
)
 
12.5

Tax effect of above adjustments
(23.9
)
 
17.2

 
(29.0
)
 
47.2

Adjusted net income (loss)
$
(84.5
)
 
$
12.5

 
$
(81.4
)
 
$
8.5

Weighted-average diluted shares outstanding
66.1

 
66.0

 
66.0

 
66.1

Adjusted diluted earnings per share
$
(1.28
)
 
$
0.19

 
$
(1.23
)
 
$
0.13



Page | 8



Adjusted EBITDAX
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Net income (loss) to adjusted EBITDAX:
 
 
 
 
 
 
 
Net income (loss)
$
(160.3
)
 
$
41.2

 
$
(173.4
)
 
$
87.4

(Gain) loss on commodity derivative instruments
116.1

 
(57.9
)
 
163.4

 
(138.6
)
Net settlements on commodity derivative instruments
(16.4
)
 
12.0

 
(42.4
)
 
12.5

Non-cash stock-based compensation
5.5

 
5.4

 
10.8

 
9.8

Interest expense, net
17.3

 
18.9

 
34.7

 
38.1

Income tax expense (benefit)
(45.3
)
 
24.5

 
(49.9
)
 
50.9

Impairment of properties and equipment
159.5

 
27.6

 
192.7

 
29.8

Exploration, geologic and geophysical expense
0.9

 
1.0

 
3.5

 
2.0

Depreciation, depletion and amortization
135.6

 
126.0

 
262.4

 
235.3

Accretion of asset retirement obligations
1.4

 
1.7

 
2.6

 
3.4

Adjusted EBITDAX
$
214.3

 
$
200.4

 
$
404.4

 
$
330.6

 
 
 
 
 
 
 
 
Cash from operating activities to adjusted EBITDAX:
 
 
 
 
 
 
 
Net cash from operating activities
$
175.7

 
$
132.9

 
$
380.9

 
$
272.4

Interest expense, net
17.3

 
18.9

 
34.7

 
38.1

Amortization of debt discount and issuance costs
(3.1
)
 
(3.2
)
 
(6.4
)
 
(6.4
)
Gain (loss) on sale of properties and equipment
0.4

 
0.5

 
(1.1
)
 
0.7

Exploration, geologic and geophysical expense
0.9

 
1.0

 
3.5

 
2.0

Other
(0.5
)
 
40.3

 
(0.6
)
 
39.6

Changes in assets and liabilities
23.6

 
10.0

 
(6.6
)
 
(15.8
)
Adjusted EBITDAX
$
214.3

 
$
200.4

 
$
404.4

 
$
330.6





Page | 9



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

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
Crude oil, natural gas and NGLs sales
$
325,933

 
$
213,602

 
$
631,158

 
$
403,294

Commodity price risk management gain (loss), net
(116,126
)
 
57,932

 
(163,366
)
 
138,636

Other income
2,724

 
3,624

 
5,339

 
6,935

Total revenues
212,531

 
275,158

 
473,131

 
548,865

Costs, expenses and other
 
 
 
 
 
 
 
Lease operating expenses
32,260

 
20,028

 
61,896

 
39,817

Production taxes
22,604

 
15,042

 
42,773

 
27,441

Transportation, gathering and processing expenses
8,964

 
6,488

 
16,277

 
12,390

Exploration, geologic and geophysical expense
875

 
1,033

 
3,521

 
1,987

Impairment of properties and equipment
159,554

 
27,566

 
192,742

 
29,759

General and administrative expense
37,247

 
29,531

 
72,943

 
55,846

Depreciation, depletion and amortization
135,624

 
126,013

 
262,412

 
235,329

Accretion of asset retirement obligations
1,285

 
1,666

 
2,573

 
3,434

(Gain) loss on sale of properties and equipment
(351
)
 
(532
)
 
1,081

 
(692
)
Provision for uncollectible note receivable

 
(40,203
)
 

 
(40,203
)
Other expenses
2,708

 
3,890

 
5,476

 
7,418

Total costs, expenses and other
400,770

 
190,522

 
661,694

 
372,526

Income (loss) from operations
(188,239
)
 
84,636

 
(188,563
)
 
176,339

Interest expense
(17,410
)
 
(19,617
)
 
(34,939
)
 
(39,084
)
Interest income
69

 
768

 
217

 
1,008

Income (loss) before income taxes
(205,580
)
 
65,787

 
(223,285
)
 
138,263

Income tax (expense) benefit
45,323

 
(24,537
)
 
49,889

 
(50,867
)
Net income (loss)
$
(160,257
)
 
$
41,250

 
$
(173,396
)
 
$
87,396

 
 
 
 
 
 
 
 
Earnings per share:
 
 
 
 
 
 
 
Basic
$
(2.43
)
 
$
0.63

 
$
(2.63
)
 
$
1.33

Diluted
$
(2.43
)
 
$
0.62

 
$
(2.63
)
 
$
1.32

 
 
 
 
 
 
 
 
Weighted-average common shares outstanding:
 
 
 
 
 
 
 
Basic
66,066

 
65,859

 
66,012

 
65,804

Diluted
66,066

 
66,019

 
66,012

 
66,066









Page | 10




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

 
 
June 30, 2018
 
December 31, 2017
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
1,425

 
$
180,675

Accounts receivable, net
 
195,317

 
197,598

Fair value of derivatives
 
14,817

 
14,338

Prepaid expenses and other current assets
 
6,744

 
8,613

Total current assets
 
218,303

 
401,224

Properties and equipment, net
 
4,192,608

 
3,933,467

Assets held-for-sale, net
 

 
40,084

Other assets
 
31,243

 
45,116

Total Assets
 
$
4,442,154

 
$
4,419,891

 
 
 
 
 
Liabilities and Stockholders' Equity
 
 
 
 
Liabilities
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
215,150

 
$
150,067

Production tax liability
 
56,766

 
37,654

Fair value of derivatives
 
186,605

 
79,302

Funds held for distribution
 
102,354

 
95,811

Accrued interest payable
 
12,561

 
11,815

Other accrued expenses
 
35,888

 
42,987

Total current liabilities
 
609,324

 
417,636

Long-term debt
 
1,179,117

 
1,151,932

Deferred income taxes
 
141,811

 
191,992

Asset retirement obligations
 
73,549

 
71,006

Fair value of derivatives
 
36,430

 
22,343

Other liabilities
 
61,617

 
57,333

Total liabilities
 
2,101,848

 
1,912,242

 
 
 
 
 
Commitments and contingent liabilities
 
 
 
 
 
 
 
 
 
Stockholders' equity
 
 
 
 
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,133,025 and 65,955,080 issued as of June 30, 2018 and December 31, 2017, respectively
 
661

 
659

Additional paid-in capital
 
2,509,693

 
2,503,294

Retained earnings (deficit)
 
(166,692
)
 
6,704

Treasury shares - at cost, 67,169 and 55,927
as of June 30, 2018 and December 31, 2017, respectively
 
(3,356
)
 
(3,008
)
Total stockholders' equity
 
2,340,306

 
2,507,649

Total Liabilities and Stockholders' Equity
 
$
4,442,154

 
$
4,419,891

 
 
 
 
 

Page | 11



PDC ENERGY, INC.
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2018
 
2017
 
2018
 
2017
Cash flows from operating activities:
 
 
 
 
 
 
 
 
Net income (loss)
 
$
(160,257
)
 
$
41,250

 
$
(173,396
)
 
$
87,396

Adjustments to net income (loss) to reconcile to net cash from operating activities:
 
 
 
 
 
 
 
 
Net change in fair value of unsettled commodity derivatives
 
99,718

 
(45,917
)
 
120,920

 
(126,070
)
Depreciation, depletion and amortization
 
135,624

 
126,013

 
262,412

 
235,329

Impairment of properties and equipment
 
159,554

 
27,566

 
192,742

 
29,759

Provision for uncollectible notes receivable
 

 
(40,203
)
 

 
(40,203
)
Accretion of asset retirement obligations
 
1,285

 
1,666

 
2,573

 
3,434

Non-cash stock-based compensation
 
5,518

 
5,372

 
10,779

 
9,826

(Gain) loss on sale of properties and equipment
 
(351
)
 
(532
)
 
1,081

 
(692
)
Amortization of debt discount and issuance costs
 
3,126

 
3,215

 
6,372

 
6,399

Deferred income taxes
 
(45,372
)
 
24,487

 
(50,181
)
 
50,767

Other
 
459

 
(52
)
 
974

 
670

Changes in assets and liabilities
 
(23,596
)
 
(9,918
)
 
6,581

 
15,832

Net cash from operating activities
 
175,708

 
132,947

 
380,857

 
272,447

Cash flows from investing activities:
 
 
 
 
 
 
 
 
Capital expenditures for development of crude oil and natural gas properties
 
(235,718
)
 
(204,580
)
 
(432,635
)
 
(334,406
)
Capital expenditures for other properties and equipment
 
(1,384
)
 
(1,478
)
 
(2,450
)
 
(2,299
)
Acquisition of crude oil and natural gas properties, including settlement adjustments
 
(227
)
 
(809
)
 
(181,052
)
 
5,372

Proceeds from sale of properties and equipment
 
1,762

 
556

 
1,782

 
1,293

Proceeds from divestiture
 

 

 
39,023

 

Sale of promissory note
 

 
40,203

 

 
40,203

Restricted cash
 

 
(9,250
)
 
1,249

 
(9,250
)
Sale of short-term investments
 

 
49,890

 

 
49,890

Purchases of short-term investments
 

 

 

 
(49,890
)
Net cash from investing activities
 
(235,567
)
 
(125,468
)
 
(574,083
)
 
(299,087
)
Cash flows from financing activities:
 
 
 
 
 
 
 
 
Proceeds from revolving credit facility
 
198,000

 

 
233,000

 

Repayment of revolving credit facility
 
(176,000
)
 

 
(211,000
)
 

Payment of debt issuance costs
 
(4,060
)
 

 
(4,060
)
 

Purchases of treasury stock
 
(2,239
)
 
(3,257
)
 
(4,494
)
 
(5,274
)
Other
 
(340
)
 
(305
)
 
(719
)
 
(645
)
Net cash from financing activities
 
15,361

 
(3,562
)
 
12,727

 
(5,919
)
Net change in cash, cash equivalents and restricted cash
 
(44,498
)
 
3,917

 
(180,499
)
 
(32,559
)
Cash, cash equivalents and restricted cash, beginning of period
 
53,924

 
207,624

 
189,925

 
244,100

Cash, cash equivalents and restricted cash, end of period
 
$
9,426

 
$
211,541

 
$
9,426

 
$
211,541


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Page |

Page |
2018 Second 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 Thursday, August 9, 2018 to discuss its 2018 second quarter results. The related slide presentation will be available on PDC’s website at www.pdce.com.
Conference Call and Webcast:
Date/Time: Thursday, August 9, 2018, 11:00 a.m. ET
Webcast available at: www.pdce.com
Domestic (toll free): 877-312-5520
International: 253-237-1142
Conference ID: 53186183

Replay Numbers:
Domestic (toll free): 855-859-2056
International: 404-537-3406
Conference ID: 53186183

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 following conferences: EnerCom's The Oil and Gas Conference in Denver on Tuesday, August 21, 2018; Barclay’s CEO Energy-Power Conference in New York on Wednesday, September 5, 2018; and to attend the Johnson Rice Energy Conference in New Orleans on Tuesday, September 25, 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 produces, develops, and explores for crude oil, natural gas, and NGLs, with primary operations in the Wattenberg Field in Colorado and the

Page | 13



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.


NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q 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 and 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; the impact of potential ballot initiatives and other Colorado political matters; ability to meet our volume commitments to midstream providers; ongoing compliance with our consent decree; timing and likelihood that the Denver Metro/North Front Range NAA ozone classification will be reclassified to serious; and timing and adequacy of infrastructure projects of our midstream providers.

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;

Page | 14



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;
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 derivatives 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.


Page | 15



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 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

###


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