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

FORM 10-Q

T QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2018

or

£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to _________

Commission File Number 001-37419
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12398694&doc=11
PDC ENERGY, INC.
(Exact name of registrant as specified in its charter)

Delaware
95-2636730
(State of incorporation)
(I.R.S. Employer Identification No.)
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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer  x
Accelerated filer  o
Non-accelerated filer  o
(Do not check if a smaller reporting company)
Smaller reporting company  o
 
Emerging growth company  o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 66,073,231 shares of the Company's Common Stock ($0.01 par value) were outstanding as of July 20, 2018.


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PDC ENERGY, INC.


TABLE OF CONTENTS

 
PART I – FINANCIAL INFORMATION
 
Page
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
Item 3.
 
Item 4.
 
 
 
 
 
PART II – OTHER INFORMATION
 
 
 
 
Item 1.
 
Item 1A.
 
Item 2.
 
Item 3.
 
Item 4.
 
Item 5.
 
Item 6.
 
 
 
 
 
 
 




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SPECIAL 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; impacts of a potential ballot initiative 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;
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;


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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 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.

REFERENCES

Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships.


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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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




See accompanying Notes to Condensed Consolidated Financial Statements
1

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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

 
 
 
 
 
 
 
 
 


 

See accompanying Notes to Condensed Consolidated Financial Statements
2

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PDC ENERGY, INC.
Condensed Consolidated Statements of Cash Flows
(unaudited; in thousands)
 
 
Six Months Ended June 30,
 
 
2018
 
2017
Cash flows from operating activities:
 
 
 
 
Net income (loss)
 
$
(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
 
120,920

 
(126,070
)
Depreciation, depletion and amortization
 
262,412

 
235,329

Impairment of properties and equipment
 
192,742

 
29,759

Provision for uncollectible notes receivable
 

 
(40,203
)
Accretion of asset retirement obligations
 
2,573

 
3,434

Non-cash stock-based compensation
 
10,779

 
9,826

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

 
(692
)
Amortization of debt discount and issuance costs
 
6,372

 
6,399

Deferred income taxes
 
(50,181
)
 
50,767

Other
 
974

 
670

Changes in assets and liabilities
 
6,581

 
15,832

Net cash from operating activities
 
380,857

 
272,447

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

Proceeds from sale of properties and equipment
 
1,782

 
1,293

Proceeds from divestiture
 
39,023

 

Sale of promissory note
 

 
40,203

Restricted cash
 
1,249

 
(9,250
)
Sale of short-term investments
 

 
49,890

Purchase of short-term investments
 

 
(49,890
)
Net cash from investing activities
 
(574,083
)
 
(299,087
)
Cash flows from financing activities:
 
 
 
 
Proceeds from revolving credit facility
 
233,000

 

Repayment of revolving credit facility
 
(211,000
)
 

Payment of debt issuance costs
 
(4,060
)
 

Purchases of treasury stock
 
(4,494
)
 
(5,274
)
Other
 
(719
)
 
(645
)
Net cash from financing activities
 
12,727

 
(5,919
)
Net change in cash, cash equivalents and restricted cash
 
(180,499
)
 
(32,559
)
Cash, cash equivalents and restricted cash, beginning of period
 
189,925

 
244,100

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

 
$
211,541

 
 
 
 
 
Supplemental cash flow information:
 
 
 
 
Cash payments (receipts) for:
 
 
 
 
Interest, net of capitalized interest
 
$
27,817

 
$
32,647

Income taxes
 
393

 
(39
)
Non-cash investing and financing activities:
 
 
 
 
Change in accounts payable related to capital expenditures
 
$
72,334

 
$
81,891

Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals
 
6,248

 
2,415

Purchase of properties and equipment under capital leases
 
689

 
2,160


See accompanying Notes to Condensed Consolidated Financial Statements
3

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PDC ENERGY, INC.
Condensed Consolidated Statement of Equity
(unaudited; in thousands, except share data)

 
Common Stock
 
 
 
Treasury Stock
 
 
 
 
 
Shares
 
Amount
 
Additional Paid-in Capital
 
Shares
 
Amount
 
Retained Earnings (Deficit)
 
Total Stockholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2017
65,955,080

 
$
659

 
$
2,503,294

 
(55,927
)
 
$
(3,008
)
 
$
6,704

 
$
2,507,649

Net loss

 

 

 

 

 
(173,396
)
 
(173,396
)
Purchase of treasury shares

 

 

 
(87,063
)
 
(4,494
)
 

 
(4,494
)
Issuance of treasury shares

 

 
(4,288
)
 
78,395

 
4,288

 

 

Non-employee directors' deferred compensation plan

 

 

 
(2,574
)
 
(142
)
 

 
(142
)
Issuance of stock awards, net of forfeitures
177,945

 
2

 
(2
)
 

 

 

 

Stock-based compensation expense

 

 
10,779

 

 

 

 
10,779

Other

 

 
(90
)
 

 

 

 
(90
)
Balance, June 30, 2018
66,133,025

 
$
661

 
$
2,509,693

 
(67,169
)
 
$
(3,356
)
 
$
(166,692
)
 
$
2,340,306




See accompanying Notes to Condensed Consolidated Financial Statements
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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 Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the first quarter of 2018. As of June 30, 2018, we owned an interest in approximately 3,000 gross productive wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Our gas marketing segment does not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all periods presented.

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries and our proportionate share of our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.

In our opinion, the accompanying condensed consolidated financial statements contain all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2017 condensed consolidated balance sheet data was derived from audited statements, but does not include all disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2017 Form 10-K. Our results of operations and cash flows for the six months ended June 30, 2018 are not necessarily indicative of the results to be expected for the full year or any other future period.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Recently Adopted Accounting Standard

In May 2014, the Financial Accounting Standards Board ("FASB") and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The standard has been updated and now includes technical corrections. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations and (5) recognize revenue when or as each performance obligation is satisfied. We adopted the standard effective January 1, 2018. In order to evaluate the impact that the adoption of the revenue standard had on our consolidated financial statements, we performed a comprehensive review of our significant revenue streams. The focus of this review included, among other things, the identification of the significant contracts and other arrangements we have with our customers to identify performance obligations and principal versus agent considerations and factors affecting the determination of the transaction price. We also reviewed our current accounting policies, procedures and controls with respect to these contracts and arrangements to determine what changes, if any, would be required by the adoption of the revenue standard. We determined that we would adopt the standard under the modified retrospective method. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. See the footnote below titled Revenue Recognition for further details regarding the changes in our revenue recognition resulting from the adoption of this standard.

In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that the statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. The adoption of this standard impacted our condensed consolidated statements of cash flows. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the condensed consolidated balance sheets at June 30, 2018 and 2017 and December 31, 2017, which sum to the total of cash, cash equivalents and restricted cash in the condensed consolidated statements of cash flows:
 
June 30, 2018
 
December 31, 2017
 
June 30, 2017
 
(in thousands)
 
 
 
 
 
 
Cash and cash equivalents
$
1,425

 
$
180,675

 
$
202,291

Restricted cash
8,001

 
9,250

 
9,250

Cash, cash equivalents and restricted cash shown in the condensed consolidated statements of cash flows
$
9,426

 
$
189,925

 
$
211,541

 
Restricted cash is included in other assets on the condensed consolidated balance sheets at June 30, 2018 and December 31, 2017. We did not have any cash classified as restricted cash at December 31, 2016.

Recently Issued Accounting Standards

In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. The standard has been updated and now includes amendments. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.

In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.    

NOTE 3 - BUSINESS COMBINATION

In January 2018, we closed the acquisition of properties from Bayswater Exploration and Production LLC (the "Bayswater Acquisition") for approximately $202.0 million in cash, including $21.0 million deposited into an escrow account in September 2017, subject to certain customary post-closing adjustments. The $21.0 million deposit was included in other assets on our December 31, 2017 condensed consolidated balance sheet. We acquired approximately 7,400 net acres, approximately 220 gross drilling locations and 24 operated horizontal wells that were either drilled uncompleted wells ("DUCs") or in-process wells at the time of closing.

The estimated allocation of the assets acquired and the liabilities assumed in the acquisition are presented below and are subject to customary post-closing adjustments. Adjustments to the preliminary purchase price stem from final settlement of the proceeds from operating activities and additional information we obtained about facts and circumstances that existed at the acquisition date that impact the underlying value of certain assets acquired and current liabilities assumed. Such adjustments primarily relate to sales, operating expenses and capital costs from the effective date through closing.


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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


The details of the estimated purchase price and the allocation of the purchase price for the transaction, are presented below (in thousands):
 
June 30, 2018
Acquisition costs:
 
       Cash
$
170,560

       Deposit made in prior period
21,000

  Total cash consideration
191,560

        Other purchase price adjustments
10,422

  Total acquisition costs
$
201,982

 
 
Recognized amounts of identifiable assets acquired and liabilities assumed:
 
Assets acquired:
 
       Current assets
$
517

       Crude oil and natural gas properties - proved
207,816

       Other assets
2,796

Total assets acquired
211,129

Liabilities assumed:
 
       Current liabilities
(4,460
)
       Asset retirement obligations
(4,687
)
Total liabilities assumed
(9,147
)
Total identifiable net assets acquired
$
201,982


This transaction was accounted for under the acquisition method. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, lease terms and expirations and a market-based weighted-average cost of capital rate. The allocation of the value to the underlying leases also requires significant judgment and is based on a combination of comparable market transactions, the term and conditions associated with the individual leases, our ability and intent to develop specific leases and our initial assessment of the underlying relative value of the leases given our knowledge of the geology at the time of closing. These inputs require significant judgments and estimates by management at the time of the valuation.

The results of operations for the Bayswater Acquisition for the three and six months ended June 30, 2018 have been included in our condensed consolidated financial statements, including approximately $14.5 million and $21.8 million, respectively, of total revenue, $8.3 million and $12.0 million, respectively, of income from operations and $0.12 and $0.18, respectively, of diluted earnings per share. Pro forma results of operations for the Bayswater Acquisition showing results as if the acquisition had been completed as of January 1, 2017 would not have been material to our condensed consolidated financial statements for the three and six months ended June 30, 2017.

NOTE 4 - REVENUE RECOGNITION

On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $2.8 million and $5.4 million in the three and six months ended June 30, 2017, respectively, with a

7

Table of contents
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for the three and six months ended June 30, 2018, we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the New Revenue Standard to have a significant impact on our net income going forward.

Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the three and six months ended June 30, 2018 and 2017, the impact of any natural gas imbalances was not significant. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded.

Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas, or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid.

We use the gross method of accounting when control of the crude oil, natural gas, or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses.

Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the New Revenue Standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method.

As discussed above, we enter into agreements for the sale, transportation, gathering and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based upon first-of-the-month index prices, as in each case this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements.  For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes.





8

Table of contents
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the three and six months ended June 30, 2018 and 2017 (in thousands):

 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Revenue by Commodity and Operating Region
 
2018
 
2017 (1)
 
Percentage Change
 
2018
 
2017 (1)
 
Percentage Change
Crude oil
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
$
189,992

 
$
129,258

 
47.0
 %
 
$
360,299

 
$
234,446

 
53.7
 %
Delaware Basin
 
62,599

 
16,327

 
283.4
 %
 
116,016

 
29,865

 
288.5
 %
Utica Shale (2)
 

 
3,216

 
(100.0
)%
 
2,696

 
7,486

 
(64.0
)%
Total
 
$
252,591

 
$
148,801

 
69.8
 %
 
$
479,011

 
$
271,797

 
76.2
 %
 Natural gas
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
$
22,640

 
$
34,004

 
(33.4
)%
 
$
52,412

 
$
66,617

 
(21.3
)%
Delaware Basin
 
7,472

 
2,767

 
170.0
 %
 
15,151

 
5,236

 
189.4
 %
Utica Shale (2)
 

 
1,561

 
(100.0
)%
 
1,109

 
3,421

 
(67.6
)%
Total
 
$
30,112

 
$
38,332

 
(21.4
)%
 
$
68,672

 
$
75,274

 
(8.8
)%
NGLs
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
$
30,271

 
$
21,923

 
38.1
 %
 
$
59,041

 
$
47,242

 
25.0
 %
Delaware Basin
 
12,959

 
3,680

 
252.1
 %
 
23,594

 
6,626

 
256.1
 %
Utica Shale (2)
 

 
866

 
(100.0
)%
 
840

 
2,355

 
(64.3
)%
Total
 
$
43,230

 
$
26,469

 
63.3
 %
 
$
83,475

 
$
56,223

 
48.5
 %
Revenue by Operating Region
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
$
242,903

 
$
185,185

 
31.2
 %
 
$
471,752

 
$
348,305

 
35.4
 %
Delaware Basin
 
83,030

 
22,774

 
264.6
 %
 
154,761

 
41,727

 
270.9
 %
Utica Shale (2)
 

 
5,643

 
(100.0
)%
 
4,645

 
13,262

 
(65.0
)%
Total
 
$
325,933

 
$
213,602

 
52.6
 %
 
$
631,158

 
$
403,294

 
56.5
 %
________________________________________
(1)
As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for the three
 
and six months ended June 30, 2017 have not been restated. Such changes would not have been material.
(2)
In March 2018, we completed the disposition of our Utica Shale properties.

Contract Assets.    Contract assets include material contributions in aid of construction ("CIAC"), which are common in purchase/purchase and processing agreements with midstream service providers that are our customers. Generally, the intent of the payments is to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets that are classified as current assets are included in prepaid expenses and other current assets on our condensed consolidated balance sheet. Contract assets that are classified as long-term assets are included in other assets on our condensed consolidated balance sheet. The contract assets will be amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer.

The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for the six months ended June 30, 2018:
 
Amount
 
(in thousands)
 
 
Beginning balance, January 1, 2018
$
4,446

Additions
1,202

Amortized as a reduction to crude oil, natural gas and NGLs sales
(2,408
)
Ending balance, June 30, 2018
$
3,240


Customer Accounts Receivable. Our accounts receivable include amounts billed and currently due from sales of our crude oil, natural gas and NGLs production. Our gross accounts receivable balance from crude oil, natural gas and NGLs sales at June 30, 2018 and December 31, 2017 was $159.1 million and $154.3 million, respectively. We did not record an allowance for doubtful accounts for these receivables at June 30, 2018 or December 31, 2017.

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)



NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Determination of Fair Value

Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.

Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.

Derivative Financial Instruments

We measure the fair value of our derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

We validate our fair value measurement through the review of counterparty statements and other supporting documentation, determination that the source of the inputs is valid, corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.

Our crude oil and natural gas fixed-price swaps are included in Level 2 of the hierarchy. Our collars and propane fixed-price swaps are included in Level 3 of the hierarchy. Our basis swaps are included in Level 2 and Level 3 of the hierarchy. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:
 
June 30, 2018
 
December 31, 2017
 
Significant Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  
Total
 
Significant Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  
Total
 
(in thousands)
Total assets
$
10,412

 
$
4,405

 
$
14,817

 
$
12,949

 
$
1,389

 
$
14,338

Total liabilities
(199,530
)
 
(23,505
)
 
(223,035
)
 
(90,569
)
 
(11,076
)
 
(101,645
)
Net liability
$
(189,118
)
 
$
(19,100
)
 
$
(208,218
)
 
$
(77,620
)
 
$
(9,687
)
 
$
(87,307
)
 
 
 
 
 
 
 
 
 
 
 
 

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


The following table presents a reconciliation of our Level 3 assets measured at fair value:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period
 
$
(8,834
)
 
$
2,316

 
$
(9,687
)
 
$
(9,574
)
Changes in fair value included in condensed consolidated statement of operations line item:
 
 
 
 
 
 
 
 
Commodity price risk management gain (loss), net
 
(4,701
)
 
9,262

 
(6,854
)
 
22,622

Settlements included in condensed consolidated statement of operations line items:
 
 
 
 
 
 
 
 
Commodity price risk management gain (loss), net
 
(5,565
)
 
(2,959
)
 
(2,559
)
 
(4,429
)
Fair value of Level 3 instruments, net asset (liability) end of period
 
$
(19,100
)
 
$
8,619

 
$
(19,100
)
 
$
8,619

 
 
 
 
 
 
 
 
 
Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item:
 
 
 
 
 
 
 
 
Commodity price risk management gain (loss), net
 
$
(15,582
)
 
$
8,161

 
$
(9,412
)
 
$
17,194

 
 
 
 
 
 
 
 
 

The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by this report.
        
Non-Derivative Financial Assets and Liabilities

The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

We utilize fair value on a nonrecurring basis to review our proved crude oil and natural gas properties for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold.
 
The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of:
 
 
As of June 30, 2018
 
As of December 31, 2017
 
 
Estimated Fair Value
 
Percent of Par
 
Estimated Fair Value
 
Percent of Par
 
 
(in millions)
 
 
 
(in millions)
 
 
Senior notes:
 
 
 
 
 
 
 
 
2021 Convertible Notes
$
209.2

 
104.6
%
 
$
195.6

 
97.8
%
 
2024 Senior Notes
408.4

 
102.1
%
 
416.0

 
104.0
%
 
2026 Senior Notes
599.7

 
99.9
%
 
616.5

 
102.8
%

The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the related vehicle lease.


11

Table of contents
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


Concentration of Risk

Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at June 30, 2018, taking into account the estimated likelihood of nonperformance.

Note Receivable. In 2014, we sold our entire 50 percent ownership interest in PDC Mountaineer, LLC to an unrelated third-party. As part of the consideration, we received a promissory note (the “Promissory Note”) for a principal sum of $39.0 million, bearing variable interest rates. We regularly analyzed the Promissory Note for evidence of collectibility, evaluating factors such as the creditworthiness of the issuer of the Promissory Note and the value of the issuer's assets. Based upon this analysis, during the quarter ended March 31, 2016, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.0 million accumulated outstanding balance, including interest. In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately $40.2 million in cash. Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during the second quarter of 2017.

Cash and Cash Equivalents. We consider all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of the FDIC insurance limits at June 30, 2018 and December 31, 2017. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also major lenders under our revolving credit facility.

NOTE 6 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil, natural gas and propane, which is an element of our NGLs, we enter into commodity derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases.
 
We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of June 30, 2018, we had derivative instruments, which were comprised of collars, fixed-price swaps and basis protection swaps, in place for a portion of our anticipated 2018, 2019 and 2020 production. Our commodity derivative contracts have been entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount.


12

Table of contents
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


As of June 30, 2018, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
 
 
Collars
 
Fixed-Price Swaps
 
 
Commodity/ Index/
Maturity Period
 
Quantity
(Crude oil -
MBls
Natural Gas - BBtu)
 
Weighted-Average
Contract Price
 
Quantity (Crude Oil - MBbls
Gas and Basis-
BBtu
 Propane - MBbls)
 
Weighted-
Average
Contract
Price
 
Fair Value
June 30,
2018 (1)
(in thousands)
 
 
Floors
 
Ceilings
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
 
 
 
 
NYMEX
 
 
 
 
 
 
 
 
 
 
 
 
2018
 
1,106.0

 
$
46.01

 
$
57.11

 
5,636.0

 
$
52.34

 
$
(117,210
)
2019
 
1,400.0

 
53.57

 
65.55

 
8,400.0

 
53.86

 
(99,002
)
2020
 

 

 

 
600.0

 
62.50

 
343

Total Crude Oil
 
2,506.0

 
 
 
 
 
14,636.0

 
 
 
$
(215,869
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
 
 
 
 
 
 
 
 
 
 
 
NYMEX
 
 
 
 
 
 
 
 
 
 
 
 
2018
 
240.0

 
$
3.00

 
$
3.90

 
27,715.0

 
$
2.94

 
$
(541
)
2019
 

 

 

 
8,004.0

 
2.78

 
(218
)
Dominion South
 
 
 
 
 
 
 
 
 
 
 
 
2018
 

 

 

 
399.0

 
2.12

 
12

2019
 

 

 

 
256.6

 
2.13

 
7

Total Natural Gas
 
240.0

 
 
 
 
 
36,396.2

 
 
 
$
(740
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Basis Protection - Crude Oil
 
 
 
 
 
 
 
 
 
 
 
 
Midland Cushing
 
 
 
 
 
 
 
 
 
 
 
 
2018
 

 
$

 
$

 
343.9

 
$
(0.10
)
 
$
4,374

Total Basis Protection - Crude Oil
 

 
 
 
 
 
343.9

 
 
 
$
4,374

 
 
 
 
 
 
 
 
 
 
 
 
 
Basis Protection - Natural Gas
 
 
 
 
 
 
 
 
 
 
 
 
CIG
 
 
 
 
 
 
 
 
 
 
 
 
2018
 

 
$

 
$

 
19,612.0

 
$
(0.42
)
 
$
6,440

2019
 

 

 

 
7,924.0

 
(0.88
)
 
(369
)
Waha
 
 
 
 
 
 
 
 
 
 
 
 
2018
 

 

 

 
3,425.0

 
(0.50
)
 
2,842

Total Basis Protection - Natural Gas
 

 
 
 
 
 
30,961.0

 
 
 
$
8,913

 
 
 
 
 
 
 
 
 
 
 
 
 
Propane
 
 
 
 
 
 
 
 
 
 
 
 
Mont Belvieu
 
 
 
 
 
 
 
 
 
 
 
 
2018
 

 
$

 
$

 
333.4

 
$
33.97

 
$
(1,882
)
Total Propane
 

 
 
 
 
 
333.4

 
 
 
$
(1,882
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Rollfactor (2)
 
 
 
 
 
 
 
 
 
 
 
 
Crude Oil CMA
 
 
 
 
 
 
 
 
 
 
 
 
2018
 

 
$

 
$

 
2,934.3

 
$
0.13

 
$
(3,014
)
Total Rollfactor
 

 
 
 
 
 
2,934.3

 
 
 
$
(3,014
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivatives Fair Value
 
 
 
 
 
 
 
$
(208,218
)
_____________
(1)
Approximately 29.9 percent of the fair value of our commodity derivative assets and 10.5 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).
(2)
These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month.

13

Table of contents
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)



We have not elected to designate any of our derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the condensed consolidated statements of operations.

The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets:
 
 
 
 
 
Fair Value
Derivative Instruments:
 
Condensed Consolidated Balance Sheet Line Item
 
June 30, 2018
 
December 31, 2017
 
 
 
 
 
(in thousands)
Derivative assets:
Current
 
 
 
 
 
 
 
Commodity derivative contracts
 
Fair value of derivatives
 
$
1,161

 
$
7,340

 
Basis protection derivative contracts
 
Fair value of derivatives
 
13,656

 
6,998

 
 
 
 
 
14,817

 
14,338

 
Non-current
 
Fair value of derivatives
 

 

Total derivative assets
 
 
 
$
14,817

 
$
14,338

 
 
 
 
 
 
 
 
Derivative liabilities:
Current
 
 
 
 
 
 
 
Commodity derivative contracts
 
Fair value of derivatives
 
$
183,369

 
$
77,999

 
Basis protection derivative contracts
 
Fair value of derivatives
 
222

 
234

 
Rollfactor derivative contracts
 
Fair value of derivatives
 
3,014

 
1,069

 
 
 
 
 
186,605

 
79,302

 
Non-current
 
 
 
 
 
 
 
Commodity derivative contracts
 
Fair value of derivatives
 
36,283

 
22,343

 
Basis protection derivative contracts
 
Fair value of derivatives
 
147

 

 
 
 
 
 
36,430

 
22,343

Total derivative liabilities
 
 
 
$
223,035

 
$
101,645

    
The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Condensed Consolidated Statement of Operations Line Item
 
2018
 
2017
 
2018
 
2017
 
 
(in thousands)
Commodity price risk management gain (loss), net
 
 
 
 
 
 
 
 
Net settlements
 
$
(16,408
)
 
$
12,015

 
$
(42,446
)
 
$
12,566

Net change in fair value of unsettled derivatives
 
(99,718
)
 
45,917

 
(120,920
)
 
126,070

Total commodity price risk management gain (loss), net
 
$
(116,126
)
 
$
57,932

 
$
(163,366
)
 
$
138,636

 
 
 
 
 
 
 
 
 

Net settlements of commodity derivatives and net change in fair value of unsettled derivatives decreased for the three and six months ended June 30, 2018 as compared to the three and six months ended June 30, 2017 as a result of the increase in future commodity prices during the first half of 2018 compared to a decrease during the first half of 2017. Our decrease in net settlements for the three months ended June 30, 2018 was partially offset by an $11.3 million realized gain on the early settlement of certain commodity derivative basis protection positions, including $10.3 million for the early settlement of crude oil basis protection instruments and $1.0 million for the early settlement of natural gas basis protection instruments, both for our Delaware Basin operations. The volumes associated with these instruments were impacted by certain marketing agreements entered into during the three months ended June 30, 2018 which eliminated the underlying sale price variability, and therefore there was no longer a variable to hedge.

All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets.


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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


The following table reflects the impact of netting agreements on gross derivative assets and liabilities:
As of June 30, 2018
 
Derivative Instruments, Gross
 
Effect of Master Netting Agreements
 
Derivative Instruments, Net
 
 
(in thousands)
Asset derivatives:
 
 
 
 
 
 
Derivative instruments, at fair value
 
$
14,817

 
$
(14,752
)
 
$
65

 
 
 
 
 
 
 
Liability derivatives:
 
 
 
 
 
 
Derivative instruments, at fair value
 
$
223,035

 
$
(14,752
)
 
$
208,283

 
 
 
 
 
 
 
As of December 31, 2017
 
Derivative Instruments, Gross
 
Effect of Master Netting Agreements
 
Derivative Instruments, Net
 
 
(in thousands)
Asset derivatives:
 
 
 
 
 
 
Derivative instruments, at fair value
 
$
14,338

 
$
(14,173
)
 
$
165

 
 
 
 
 
 
 
Liability derivatives:
 
 
 
 
 
 
Derivative instruments, at fair value
 
$
101,645

 
$
(14,173
)
 
$
87,472

 
 
 
 
 
 
 

NOTE 7 - PROPERTIES AND EQUIPMENT

The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization ("DD&A"):

 
June 30, 2018
 
December 31, 2017
 
(in thousands)
Properties and equipment, net:
 
 
 
Crude oil and natural gas properties
 
 
 
Proved
$
4,944,476

 
$
4,356,922

Unproved
908,271

 
1,097,317

Total crude oil and natural gas properties
5,852,747

 
5,454,239

Infrastructure, pipeline and other
127,799

 
109,359

Land and buildings
12,724

 
10,960

Construction in progress
294,669

 
196,024

Properties and equipment, at cost
6,287,939

 
5,770,582

Accumulated DD&A
(2,095,331
)
 
(1,837,115
)
Properties and equipment, net
$
4,192,608

 
$
3,933,467

 
 
 
 

The following table presents impairment charges recorded for crude oil and natural gas properties:

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)

 
 
 
 
 
 
 
Impairment of proved and unproved properties
$
159,528

 
$
27,463

 
$
192,658

 
$
29,565

Amortization of individually insignificant unproved properties
26

 
103

 
84

 
194

Impairment of crude oil and natural gas properties
$
159,554

 
$
27,566

 
$
192,742

 
$
29,759

    

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


During the six months ended June 30, 2018, we recorded impairment charges totaling $192.7 million, including $159.5 million during the three months ended June 30, 2018. During the three months ended June 30, 2018, we identified current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin and made the determination that we would no longer pursue plans to develop these properties. The impaired non-focus leasehold typically has a higher gas to oil ratio and a greater degree of geologic complexity than our other Delaware Basin properties and is further impacted by widening natural gas differentials and increased well development costs. We intend to focus our future Delaware Basin development in our oilier core areas where we have identified approximately 450 mid-length lateral equivalent Wolfcamp drilling locations. We continue to explore options for our non-focus areas and monitor them for possible future impairment based on similar analyses. We determined the fair value of the properties based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold.

Additionally, we corrected an error in our calculation of the unproved properties and goodwill impairment originally reported in the quarter ended September 30, 2017. The correction of the error resulted in an additional impairment charge of $6.3 million, recorded in the three months ended March 31, 2018, which we have included in the impairment of properties and equipment expense line in our condensed consolidated statement of operations. We evaluated the error under the guidance of Accounting Standards Codification 250, Accounting Changes and Error Corrections ("ASC 250"). Based on the guidance in ASC 250, we determined that the impact of the error did not have a material impact on our previously-issued financial statements or those of the period of correction.
        
Utica Shale Divestiture. In March 2018, we completed the disposition of our Utica Shale properties (the "Utica Shale Divestiture") for net cash proceeds of approximately $39.0 million. We recorded a loss on sale of properties and equipment of $1.4 million for the six months ended June 30, 2018, which included post-closing adjustments. The divestiture of the Utica Shale properties did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for it as a discontinued operation.
    
Suspended Well Costs. We have spud one well in the Delaware Basin for which we are unable to make a final determination regarding whether proved reserves can be associated with the well as of June 30, 2018 as the well had not been completed as of that date. Therefore, we have classified the capitalized costs of the well as suspended well costs as of June 30, 2018 while we continue to conduct completion and testing operations to determine the existence of proved reserves.

The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the condensed consolidated balance sheets:
 
Six Months Ended June 30, 2018
 
Year Ended December 31, 2017
 
(in thousands, except for number of wells)
 
 
 
 
Beginning balance
$
15,448

 
$

Additions to capitalized exploratory well costs pending the determination of proved reserves
23,443

 
51,776

   Reclassifications to proved properties
(29,883
)
 
(36,328
)
   Capitalized exploratory well costs charged to expense

 

Ending balance
$
9,008

 
$
15,448

 
 
 
 
Number of wells pending determination at period end
1

 
3

    

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


NOTE 8 - OTHER ACCRUED EXPENSES AND OTHER LIABILITIES

Other Accrued Expenses. The following table presents the components of other accrued expenses as of:
 
 
June 30, 2018
 
December 31, 2017
 
 
(in thousands)
 
 
 
 
 
Employee benefits
 
$
14,609

 
$
22,383

Asset retirement obligations
 
15,959

 
15,801

Environmental expenses
 
2,355

 
1,374

Other
 
2,965

 
3,429

Other accrued expenses
 
$
35,888

 
$
42,987

 
 
 
 
 

Other Liabilities. The following table presents the components of other liabilities as of:
 
 
June 30, 2018
 
December 31, 2017
 
 
(in thousands)
 
 
 
 
 
Production taxes
 
$
28,537

 
$
50,476

Deferred oil gathering credit
 
23,115

 

Other
 
9,965

 
6,857

Other liabilities
 
$
61,617

 
$
57,333

 
 
 
 
 

Deferred Oil Gathering Credit. On January 31, 2018, we received a payment of $24.1 million from Saddle Butte Rockies Midstream, LLC for the execution of an amendment to an existing crude oil purchase and sale agreement signed in December 2017. The amendment was effective contingent upon certain events which occurred in late January 2018. The amendment, among other things, dedicates crude oil from the majority of our Wattenberg Field acreage to Saddle Butte's gathering lines and extends the term of the agreement through December 2029. The payment will be amortized using the straight-line method over the life of the amendment. Amortization charges totaling approximately $0.4 million and $0.7 million for the three and six months ended June 30, 2018 related to the deferred oil gathering credit are included as a reduction to transportation, gathering and processing expenses on our condensed consolidated statements of operations.

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


NOTE 9 - LONG-TERM DEBT

Long-term debt consisted of the following as of:
 
June 30, 2018
 
December 31, 2017
 
(in thousands)
Senior notes:
 
 
 
1.125% Convertible Notes due September 2021:
 
 
 
Principal amount
$
200,000

 
$
200,000

Unamortized discount
(26,600
)
 
(30,328
)
Unamortized debt issuance costs
(3,128
)
 
(3,615
)
Net of unamortized discount and debt issuance costs
170,272

 
166,057

 
 
 
 
6.125% Senior Notes due September 2024:
 
 
 
Principal amount
400,000

 
400,000

Unamortized debt issuance costs
(6,080
)
 
(6,570
)
Net of unamortized debt issuance costs
393,920

 
393,430

 
 
 
 
5.75% Senior Notes due May 2026:
 
 
 
Principal amount
600,000

 
600,000

Unamortized debt issuance costs
(7,075
)
 
(7,555
)
Net of unamortized debt issuance costs
592,925

 
592,445

 
 
 
 
Total senior notes
1,157,117

 
1,151,932

 
 
 
 
Revolving credit facility due May 2023
22,000

 

Total long-term debt, net of unamortized discount and debt issuance costs
$
1,179,117

 
$
1,151,932

    
Senior Notes

2021 Convertible Notes. In September 2016, we issued $200 million of 1.125% convertible notes due September 15, 2021 (the "2021 Convertible Notes") in a public offering. Interest is payable in cash semiannually on each March 15 and September 15. The conversion price at maturity is $85.39 per share. We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments, excluding the conversion feature, priced on the same day we issued the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes were capitalized as debt issuance costs. As of June 30, 2018, the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using the effective interest method.
 
Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash, or a combination of cash and shares of our common stock. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares of our common stock, with cash paid in lieu of fractional shares.
 
2024 Senior Notes.  In September 2016, we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”) in a private placement to qualified institutional buyers. In May 2017, in accordance with the registration rights agreement that we entered into with the initial purchasers when we issued the 2024 Senior Notes, we filed a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical terms, and we completed the exchange offer in September 2017. The 2024 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually on March 15 and September 15. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method.


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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


2026 Senior Notes. In November 2017, we issued $600 million aggregate principal amount of 5.75% senior notes due May 15, 2026, in a private placement to qualified institutional buyers. In June 2018, in accordance with the registration rights agreement that we entered into with the initial purchasers when we issued the 2024 Senior Notes, we filed a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical terms, and we completed the exchange offer in July 2018. The 2026 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually on May 15 and November 15. The first interest payment occurred on May 15, 2018. Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method.

Our wholly-owned subsidiary PDC Permian, Inc. guarantees our obligations under the 2021 Convertible Notes, the 2026 Senior Notes and the 2024 Senior Notes (collectively, the "Notes"). Accordingly, condensed consolidating financial information for PDC and PDC Permian, Inc. is presented in the footnote titled Subsidiary Guarantor.

As of June 30, 2018, we were in compliance with all covenants related to the Notes.

Revolving Credit Facility

In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”) with certain banks and other lenders, including JPMorgan Chase Bank, N.A. as administrative agent. The Restated Credit Agreement amends and restates our Third Amended and Restated Credit Agreement dated as of May 21, 2013, as amended. Among other things, the Restated Credit Agreement provides for a maximum credit amount of $2.5 billion, an initial borrowing base of $1.3 billion, an initial elected commitment amount of $700 million and is subject to certain limitations under our Notes. In addition, the Restated Credit Agreement extends the maturity date of the facility from May 2020 to May 2023, reflects improved covenant flexibility and certain reductions in interest rates applicable to borrowings under the facility and includes a $25.0 million swingline facility.

The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events.

The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium) or, at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of June 30, 2018, the applicable interest margin is 0.25 percent for the alternate base rate option or 1.25 percent for the LIBOR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the revolving credit facility expires in May 2023, unless the borrowing base falls below the outstanding balance.

The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of June 30, 2018, we were in compliance with all the revolving credit facility covenants.

As of June 30, 2018 and December 31, 2017, debt issuance costs related to our revolving credit facility were $9.0 million and $6.2 million, respectively, and are included in other assets on the condensed consolidated balance sheets. As of June 30, 2018, the weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment, was 5.4 percent.
  

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Table of contents
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018
(unaudited)


NOTE 10 - CAPITAL LEASES

We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. These leases are being accounted for as capital leases as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90 percent of the fair value of the leased vehicles at inception of the lease.
 
The following table presents vehicles under capital lease as of: