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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 September 30, 2017

2021
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
pdce-20210930_g1.jpg
PDC ENERGY, INC.
(Exact name of registrant as specified in its charter)

Delaware95-2636730
(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


Securities registered pursuant to Section 12(b) of the Act.
Title of each classTicker SymbolName of each exchange on which registered
Common stock, par value $0.01 per sharePDCENasdaq Global Select Market

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 xNo 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 or an emerging growth company. See definitions of "large“large accelerated filer," "accelerated filer," "smallerfiler”, “accelerated filer”, “smaller reporting company,"company” and "emerging“emerging growth company"company” in Rule 12b-2 of the Exchange Act.
Large Accelerated FilerxAccelerated filer ☐
Non-accelerated filer  ☐Smaller reporting company ☐
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: 65,872,79097,381,111 shares of the Company's Common Stock ($0.01 par value) were outstanding as of October 20, 2017.25, 2021.


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PDC ENERGY, INC.




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PART I – FINANCIAL INFORMATIONPage
Item 1.PART I – FINANCIAL INFORMATION
Financial Statements (Unaudited)
Page
Item 1.Financial Statements
Condensed Consolidated Balance Sheets (unaudited)
1
Condensed Consolidated Statements of Operations (unaudited)
2
Condensed Consolidated Statements of Cash Flows (unaudited)
3
Condensed Consolidated StatementStatements of Stockholders’ Equity (unaudited)
4
Notes to Condensed Consolidated Financial Statements
56
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
3125
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
5245
Item 4.
Controls and Procedures
5547
PART II – OTHER INFORMATION
Item 1.
Legal Proceedings
5648
Item 1A.
Risk Factors
5748
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
5748
Item 3.
Defaults Upon Senior Securities
5748
Item 4.
Mine Safety Disclosures
5748
Item 5.
Other Information
5748
Item 6.
Exhibits
5849
SIGNATURESSignatures
5950






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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"Act”), and Section 21E of the Securities Exchange Act of 1934 ("(“Exchange Act"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."“forward-looking statements”. Words such as expects, anticipates, intends, plans, believes, seeks, estimates,expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements may include, among other things, statements regarding the closing of pending transactions and the effects of such transactions, including the fact that the pending acquisition of certain properties owned by Bayswater Exploration & Production, LLC and certain related parties and the pending acreage exchanges are subject to continuing diligence between the parties and may not occur within the expected timeframe or we may not successfully close such transactions; the potential sale of our Utica Shale properties and the timing of such sale; the level of non-operated well activity following the pending acreage exchanges; future reserves,future: production, costs and cash flows, and earnings;flows; impacts of Colorado political matters, including recent rulemaking initiatives influencing our ability to continue to obtain permits; drilling locations, zones and growth opportunities; commodity prices and differentials; capital investmentsexpenditures and projects, including expected lateral lengths of wells, drill times andthe number of rigs employed; cash flows from operations relative to future capital investments; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; adequacy of midstream infrastructure; the potential future impairments; the finalizationreturn of acapital to shareholders through buybacks of shares and/or payments of dividends; ongoing compliance with our consent decree resolving pending litigation; ratesdecree; planned redemption of return; operational enhancementsour 2025 Senior Notes; expected impact from emission reduction initiatives; risk of our counterparties non-performance on derivative instruments; and efficiencies; management of lease expiration issues; financial ratios; and midstream capacity and related curtailments and the estimated in-service date of the facilities being constructed by our midstream providers.ability to fund planned activities.


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:


•market and commodity price volatility, widening price differentials, and related impacts to the Company, including decreased revenue, income and cash flow, write-downs and impairments and decreased availability of capital;
•adverse changes to our future cash flows, liquidity and financial condition;
•changes in, worldwide production volumes and demand, including economic conditions that might impact demandinterpretations and prices for the products we produce;
volatilityenforcement of, commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices;
reductions in the borrowing base under our revolving credit facility;
impact of governmental policies and/or regulations, including changes in environmental and other laws and other political and regulatory developments, including in particular additional permit scrutiny in Colorado;
•the interpretationcoronavirus 2019 (“COVID-19”) pandemic, including its effects on commodity prices, downstream capacity, employee health and enforcement of those lawssafety, business continuity and regulations, liabilities arising thereunder, and the costs to comply with those laws and regulations;regulatory matters;
•declines in the value of our crude oil, natural gas and NGLsnatural gas liquids (“NGLs”) properties resulting in impairments;
•changes in, estimates of proved reserves;
and inaccuracy of, reserve estimates and expected production and decline 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;
•reductions in the borrowing base under our revolving credit facility;
•availability and cost 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;capital;
timing and receipt of necessary regulatory permits;
•risks incidental toinherent in the drilling and operation of crude oil and natural gas wells;
losses from our gas marketing business exceeding our expectations;•timing and costs of wells and facilities;
difficulties in integrating our operations as a result•availability, cost, and timing of any significant acquisitions, including our pending acquisitionssufficient pipeline, gathering and acreage exchanges in the Wattenberg Field;transportation facilities and related infrastructure;
increases or changes in operating costs, severance and ad valorem taxes, and increases or changes in drilling, completion, and facilities costs;
availability of supplies, materials, contractors, and services that may delay the drilling or completion of our wells;
•potential losses of acreage or other impacts due to lease expirations, other title defects, or otherwise;
increases or adverse changes in construction costs and procurement costs associated with future build out of midstream-related assets;

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future cash flows, liquidity, and financial condition;
competition within the oil and gas industry;
availability and cost of capital;
our success•risks inherent in marketing crude oil, natural gas and NGLs;
•effect of crude oil and natural gas derivativesderivative 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, including recent environmental litigation;
effect that acquisitions we may pursue have on•impact to our capital requirements;operations, personnel retention, strategy, stock price and expenses caused by the actions of activist shareholders;

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•uncertainties associated with future dividends to our shareholders;
•our ability to retain or attract senior management and key technical employees;
•civil unrest, terrorist attacks and cyber threats; 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 "Item 1A, Risk Factors," made in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2016 (the "20162020 (“2020 Form 10-K"10-K”), filed with the U.S. Securities and Exchange Commission ("SEC"(“SEC”) on February 28, 2017, 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,"“PDC Energy”, “PDC”, “the Company”, “we”, “us”, “our” or "ours"“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.statements.


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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)
(Unaudited)
September 30, 2021December 31, 2020
Assets
Current assets:
Cash and cash equivalents$99,922 $2,623 
Accounts receivable, net368,611 244,251 
Fair value of derivatives7,559 48,869 
Prepaid expenses and other current assets8,602 12,505 
Total current assets484,694 308,248 
Properties and equipment, net4,826,337 4,859,199 
Fair value of derivatives12,742 9,565 
Other assets43,492 60,961 
Total Assets$5,367,265 $5,237,973 
Liabilities and Stockholders’ Equity
Liabilities
Current liabilities:
Accounts payable$143,931 $90,635 
Production tax liability86,914 124,475 
Fair value of derivatives454,578 98,152 
Funds held for distribution261,547 177,132 
Accrued interest payable20,948 14,734 
Other accrued expenses85,520 81,715 
Current portion of long-term debt— 193,014 
Total current liabilities1,053,438 779,857 
Long-term debt1,243,235 1,409,548 
Asset retirement obligations118,361 132,637 
Fair value of derivatives133,631 36,359 
Other liabilities274,376 264,034 
Total liabilities2,823,041 2,622,435 
Commitments and contingent liabilities
Stockholders’ equity
Common shares - par value $0.01 per share, 150,000,000 authorized, 97,440,523 and 99,758,720 issued as of September 30, 2021 and December 31, 2020, respectively974 998 
Additional paid-in capital3,267,261 3,387,754 
Accumulated deficit(723,017)(772,265)
Treasury shares - at cost, 20,958 and 37,510 as of September 30, 2021 and December 31, 2020, respectively(994)(949)
Total stockholders’ equity2,544,224 2,615,538 
Total Liabilities and Stockholders’ Equity$5,367,265 $5,237,973 


See accompanying Notes to Condensed Consolidated Financial Statements
1
  September 30, 2017 December 31, 2016
Assets    
Current assets:    
Cash and cash equivalents $136,429
 $244,100
Accounts receivable, net 167,276
 143,392
Fair value of derivatives 22,916
 8,791
Prepaid expenses and other current assets 8,081
 3,542
Total current assets 334,702
 399,825
Properties and equipment, net 3,882,700
 4,002,994
Assets held-for-sale, net 41,484
 5,272
Fair value of derivatives 4,605
 2,386
Goodwill —
 62,041
Other assets 43,796
 13,324
Total Assets $4,307,287
 $4,485,842
     
Liabilities and Stockholders' Equity    
Liabilities    
Current liabilities:    
Accounts payable $164,080
 $66,322
Production tax liability 36,954
 24,767
Fair value of derivatives 25,987
 53,595
Funds held for distribution 94,387
 71,339
Accrued interest payable 18,929
 15,930
Other accrued expenses 33,451
 38,625
Total current liabilities 373,788
 270,578
Long-term debt 1,051,571
 1,043,954
Deferred income taxes 326,472
 400,867
Asset retirement obligations 78,188
 82,612
Fair value of derivatives 7,261
 27,595
Other liabilities 43,405
 37,482
Total liabilities 1,880,685
 1,863,088
     
Commitments and contingent liabilities 
 
     
Stockholders' equity    
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,928,295 and 65,704,568 issued as of September 30, 2017 and December 31, 2016, respectively 659
 657
Additional paid-in capital 2,500,532
 2,489,557
Retained earnings (deficit) (70,933) 134,208
Treasury shares - at cost, 62,772 and 28,763
 as of September 30, 2017 and December 31, 2016, respectively
 (3,656) (1,668)
Total stockholders' equity 2,426,602
 2,622,754
Total Liabilities and Stockholders' Equity $4,307,287
 $4,485,842


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PDC ENERGY, INC.
Condensed Consolidated Statements of Operations
(unaudited; in thousands, except per share data)
(Unaudited)
Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
Revenues
Crude oil, natural gas and NGLs sales$703,136 $314,920 $1,704,396 $809,156 
Commodity price risk management gain (loss), net(217,678)(68,061)(707,187)245,851 
Other income904 2,358 4,058 5,656 
Total revenues486,362 249,217 1,001,267 1,060,663 
Costs, expenses and other
Lease operating expense45,649 37,338 129,848 122,680 
Production taxes44,654 14,621 101,114 40,937 
Transportation, gathering and processing expense26,732 24,399 74,453 54,844 
Exploration, geologic and geophysical expense222 162 862 1,026 
General and administrative expense30,847 32,490 96,367 130,007 
Depreciation, depletion and amortization169,644 144,504 478,617 470,152 
Accretion of asset retirement obligations2,825 2,420 9,185 7,398 
Impairment of properties and equipment77 1,221 329 882,327 
Loss (gain) on sale of properties and equipment(220)(289)(561)(642)
Other303 1,936 2,496 6,083 
Total costs, expenses and other320,733 258,802 892,710 1,714,812 
Income (loss) from operations165,629 (9,585)108,557 (654,149)
Interest expense, net(20,098)(21,022)(59,199)(66,977)
Income (loss) before income taxes145,531 (30,607)49,358 (721,126)
Income tax benefit (expense)(210)(176)(110)3,496 
Net income (loss)$145,321 $(30,783)$49,248 $(717,630)
Earnings (Loss) per share:
Basic$1.48 $(0.31)$0.50 $(7.34)
Diluted$1.45 $(0.31)$0.49 $(7.34)
Weighted-average common shares outstanding:
Basic98,183 99,617 99,018 97,762 
Diluted99,966 99,617 100,534 97,762 
Dividends declared per share$0.12 $— $0.24 $— 


See accompanying Notes to Condensed Consolidated Financial Statements
2
  Three Months Ended September 30, Nine Months Ended September 30,
  2017 2016 2017 2016
Revenues        
Crude oil, natural gas, and NGLs sales $232,733
 $141,805
 $636,027
 $328,013
Commodity price risk management gain (loss), net of settlements (52,178) 19,397
 86,458
 (62,348)
Other income 2,680
 2,688
 9,615
 9,153
Total revenues 183,235
 163,890
 732,100
 274,818
Costs, expenses and other        
Lease operating expenses 25,353
 14,001
 65,170
 43,006
Production taxes 15,516
 9,568
 42,957
 19,682
Transportation, gathering and processing expenses 9,794
 5,048
 22,184
 13,554
General and administrative expense 29,299
 32,510
 85,145
 78,868
Exploration, geologic, and geophysical expense 41,908
 241
 43,895
 688
Depreciation, depletion and amortization 125,238
 112,927
 360,567
 317,329
Impairment of properties and equipment 252,740
 933
 282,499
 6,104
Impairment of goodwill 75,121
 —
 75,121
 —
Accretion of asset retirement obligations 1,472
 1,777
 4,906
 5,400
Gain on sale of properties and equipment (62) (219) (754) (43)
Provision for uncollectible notes receivable —
 (700) (40,203) 44,038
Other expenses 2,947
 3,092
 10,365
 7,795
Total costs, expenses and other 579,326
 179,178
 951,852
 536,421
Loss from operations (396,091) (15,288) (219,752) (261,603)
Interest expense (19,275) (20,193) (58,359) (42,759)
Interest income 479
 140
 1,487
 1,875
Loss before income taxes (414,887) (35,341) (276,624) (302,487)
Income tax benefit 122,350
 12,032
 71,483
 112,198
Net loss $(292,537) $(23,309) $(205,141) $(190,289)
         
Earnings per share:        
Basic $(4.44) $(0.48) $(3.12) $(4.16)
Diluted $(4.44) $(0.48) $(3.12) $(4.16)
         
Weighted-average common shares outstanding:        
Basic 65,865
 48,839
 65,825
 45,741
Diluted 65,865
 48,839
 65,825
 45,741
         
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PDC ENERGY, INC.
Condensed Consolidated Statements of Cash Flows
(unaudited; in thousands)
(Unaudited)
Nine Months Ended September 30,
20212020
Cash flows from operating activities:
Net income (loss)$49,248 $(717,630)
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives491,830 (18,338)
Depreciation, depletion and amortization478,617 470,152 
Impairment of properties and equipment329 882,327 
Accretion of asset retirement obligations9,185 7,398 
Non-cash stock-based compensation17,294 17,441 
Gain on sale of properties and equipment(561)(642)
Amortization and write-off of debt discount, premium and issuance costs11,195 12,546 
Deferred income taxes— (2,431)
Other2,353 1,950 
Changes in assets and liabilities(31,670)(3,461)
Net cash from operating activities1,027,820 649,312 
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties(428,831)(445,505)
Capital expenditures for other properties and equipment(363)(1,940)
Acquisition of crude oil and natural gas properties— (139,812)
Proceeds from sale of properties and equipment4,720 1,539 
Proceeds from divestitures— 1,796 
Net cash from investing activities(424,474)(583,922)
Cash flows from financing activities:
Proceeds from revolving credit facility and other borrowings502,800 1,485,600 
Repayment of revolving credit facility and other borrowings(670,800)(1,204,600)
Proceeds from senior notes— 148,500 
Redemption of senior notes— (452,153)
Repayment of convertible notes(200,000)— 
Payment of debt issuance costs— (6,197)
Purchase of treasury shares for employee stock-based compensation tax withholding obligations(5,836)(8,412)
Purchase of treasury shares under stock repurchase program(107,318)(23,819)
Dividends paid(23,600)— 
Principal payments under financing lease obligations(1,293)(1,454)
Net cash from financing activities(506,047)(62,535)
Net change in cash and cash equivalents97,299 2,855 
Cash and cash equivalents, beginning of period2,623 963 
Cash and cash equivalents, end of period$99,922 $3,818 


See accompanying Notes to Condensed Consolidated Financial Statements
3
  Nine Months Ended September 30,
  2017 2016
Cash flows from operating activities:    
Net loss $(205,141) $(190,289)
Adjustments to net loss to reconcile to net cash from operating activities:    
Net change in fair value of unsettled commodity derivatives (64,307) 230,177
Depreciation, depletion and amortization 360,567
 317,329
Impairment of properties and equipment 282,499
 6,104
Impairment of goodwill 75,121
 —
Exploratory dry hole costs 41,187
 —
Provision for uncollectible notes receivable (40,203) 44,038
Accretion of asset retirement obligations 4,906
 5,400
Non-cash stock-based compensation 14,587
 15,205
Gain on sale of properties and equipment (754) (43)
Amortization of debt discount and issuance costs 9,628
 12,951
Deferred income taxes (71,529) (114,136)
Other 986
 (526)
Changes in assets and liabilities 3,855
 34,621
Net cash from operating activities 411,402
 360,831
Cash flows from investing activities:    
Capital expenditures for development of crude oil and natural gas properties (528,850) (352,213)
Capital expenditures for other properties and equipment (3,740) (1,509)
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition (14,482) (100,000)
Proceeds from sale of properties and equipment 3,322
 4,945
Sale of promissory note 40,203
 —
Restricted cash (9,250) —
Sale of short-term investments 49,890
 —
Purchase of short-term investments (49,890) —
Net cash from investing activities (512,797) (448,777)
Cash flows from financing activities:    
Proceeds from issuance of equity, net of issuance cost —
 855,072
Proceeds from senior notes —
 392,250
Proceeds from convertible senior notes —
 193,979
Proceeds from revolving credit facility —
 85,000
Repayment of revolving credit facility —
 (122,000)
Redemption of convertible notes —
 (115,000)
Purchase of treasury shares (5,325) (5,106)
Other (951) 593
Net cash from financing activities (6,276) 1,284,788
Net change in cash and cash equivalents (107,671) 1,196,842
Cash and cash equivalents, beginning of period 244,100
 850
Cash and cash equivalents, end of period $136,429
 $1,197,692
     
Supplemental cash flow information:    
Cash payments (receipts) for:    
Interest, net of capitalized interest $45,719
 $19,499
Income taxes (2,623) 167
Non-cash investing and financing activities:    
Change in accounts payable related to purchases of properties and equipment $89,974
 $(31,497)
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals 3,357
 1,137
Purchase of properties and equipment under capital leases 3,363
 1,231
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PDC ENERGY, INC.
Condensed Consolidated StatementStatements of Stockholders’ Equity
(unaudited; in thousands, except share data)thousands)

(Unaudited)
Nine Months Ended September 30, 2021
Common StockTreasury Stock
SharesAmountAdditional Paid-in CapitalSharesAmountAccumulated DeficitTotal Stockholders’ Equity
Balance, January 1, 202199,759 $998 $3,387,754 (38)$(949)$(772,265)$2,615,538 
Net loss— — — — — (9,036)(9,036)
Stock-based compensation209 2 3,670 — 1,348 — 5,020 
Purchase of treasury shares for employee stock-based compensation tax withholding obligations— — — (81)(2,356)— (2,356)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations(33)— (1,091)33 1,091 — — 
Retirement of treasury shares(568)(6)(21,061)568 21,067 — — 
Issuance of treasury shares— — — 65 — — — 
Purchase of treasury shares under stock repurchase program— — — (598)(22,098)— (22,098)
Balance, March 31, 202199,367 $994 $3,369,272 (51)$(1,897)$(781,301)$2,587,068 
Net loss— — — — — (87,037)(87,037)
Stock-based compensation295 3 5,742 — 750 — 6,495 
Purchase of treasury shares for employee stock-based compensation tax withholding obligations— — — (92)(3,300)— (3,300)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations(78)(1)(2,807)78 2,808 — — 
Retirement of treasury shares(677)(7)(26,922)684 27,235 — 306 
Issuance of treasury shares— — — 22 — — — 
Purchase of treasury shares under stock repurchase program— — — (661)(26,509)— (26,509)
Dividends declared ($0.12 per share)— — (12,117)— — — (12,117)
Balance, June 30, 202198,907 $989 $3,333,168 (20)$(913)$(868,338)$2,464,906 
Net income— $— $— — $— $145,321 $145,321 
Stock-based compensation12 — 5,730 — 49 — 5,779 
Purchase of treasury shares for employee stock-based compensation tax withholding obligations— — — (4)(180)— (180)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations(2)— (91)2 91 — — 
Retirement of treasury shares(1,476)(15)(59,610)1,476 59,625 — — 
Issuance of treasury shares— — — 1 — — — 
Purchase of treasury shares under stock repurchase program— — — (1,476)(59,666)— (59,666)
Dividends declared ($0.12 per share)— — (11,936)— — — (11,936)
Balance, September 30, 202197,441 $974 $3,267,261 (21)$(994)$(723,017)$2,544,224 




See accompanying Notes to Condensed Consolidated Financial Statements
4
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 Common Stock   Treasury Stock    
 Shares Amount Additional Paid-in Capital Shares Amount Retained Earnings (Deficit) Total Stockholders' Equity
              
Balance, December 31, 201665,704,568
 $657
 $2,489,557
 (28,763) $(1,668) $134,208
 $2,622,754
Net loss—
 —
 —
 —
 —
 (205,141) (205,141)
Purchase of treasury shares—
 —
 —
 (80,572) (5,325) —
 (5,325)
Issuance of treasury shares(49,446) —
 (3,513) 49,446
 3,513
 —
 —
Non-employee directors' deferred compensation plan—
 —
 —
 (2,883) (176) —
 (176)
Issuance of stock awards, net of forfeitures273,173
 2
 (2) —
 —
 —
 —
Stock-based compensation expense—
 —
 14,587
 —
 —
 —
 14,587
Other—
 —
 (97) —
 —
 —
 (97)
Balance, September 30, 201765,928,295
 $659
 $2,500,532
 (62,772) $(3,656) $(70,933) $2,426,602
PDC ENERGY, INC.

Condensed Consolidated Statements of Stockholders’ Equity - continued

(in thousands)
(Unaudited)

Nine Months Ended September 30, 2020
Common StockTreasury Stock
SharesAmountAdditional Paid-in CapitalSharesAmountAccumulated DeficitTotal Stockholders’ Equity
Balance, January 1, 202061,652 $617 $2,384,309 (35)$(1,474)$(47,945)$2,335,507 
Net loss— — — — — (465,015)(465,015)
Issuance pursuant to acquisition39,182 391 1,014,921 — — — 1,015,312 
Stock-based compensation121 1 3,713 — 1,958 — 5,672 
Purchase of treasury shares for employee stock-based compensation tax withholding obligations— — — (306)(7,693)— (7,693)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations(251)(3)(6,425)251 6,428 — — 
Retirement of treasury shares(1,266)(12)(23,807)1,266 23,819 — — 
Issuance of treasury shares— — — 69 — — — 
Purchase of treasury shares under stock repurchase program— — — (1,266)(23,819)— (23,819)
Balance, March 31, 202099,438 $994 $3,372,711 (21)$(781)$(512,960)$2,859,964 
Net loss— — — — — (221,832)(221,832)
Stock-based compensation213 2 6,164 — 198 — 6,364 
Purchase of treasury shares for employee stock-based compensation tax withholding obligations— — — (64)(487)— (487)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations(39)— (322)39 322 — — 
Issuance of treasury shares— — — 13 — — 
Balance, June 30, 202099,612 $996 $3,378,553 (33)$(748)$(734,792)$2,644,009 
Net loss— — — — — (30,783)(30,783)
Stock-based compensation37 — 5,216 — 189 — 5,405 
Purchase of treasury shares for employee stock-based compensation tax withholding obligations— — — (17)(232)— (232)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations(9)— (121)9 121 — — 
Issuance of treasury shares— — — 24 — — — 
Balance, September 30, 202099,640 $996 $3,383,648 (17)$(670)$(765,575)$2,618,399 

See accompanying Notes to Condensed Consolidated Financial Statements
5
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION


PDC Energy, Inc. ("PDC", the "Company," "we," "us," or "our") is a domestic independent exploration and production company that produces,acquires, explores and develops and exploresproperties for the production of crude oil, natural gas and NGLs, with primary operations in the Wattenberg Field in Colorado and beginning in December 2016, the Delaware Basin in Reeves and Culberson Counties,west Texas. We also have operations in the Utica Shale in Southeastern Ohio. During the third quarter of 2017, as part of plans to divest the Utica Shale properties, we engaged an investment banking group and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification during the third quarter of 2017. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are currentlyprimarily focused in the horizontal Wolfcamp zones. As of September 30, 2017,2021, we owned an interest in approximately 2,9003,600 gross productive wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Beginning in 2017, 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 and our wholly-owned subsidiaries, and our proportionate share of our two 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.subsidiaries. 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 forthe results of interim periods presented in accordance with accounting principles generally accepted in the United States of America ("(“U.S. GAAP"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, 20162020 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 20162020 Form 10-K. Our results of operations and cash flows for the three and nine months ended September 30, 20172021 are not necessarily indicative of the results to be expected for the full year or any other future period.


Certain immaterial reclassifications have been made to our prior period balance sheet and statement of operations to conform to the current period presentation. The reclassifications had no impact on previously reported cash flows, net earnings, earnings per share or stockholders' equity.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Recently Adopted Accounting Standard

In January 2017, the FASB issued an accounting update to simplify the measurement of goodwill. The update eliminates the two-step process that required identification of potential impairment and a separate measure of actual impairment. The annual and/or interim assessments are still required to be completed. The guidance is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the second quarter of 2017. Our annual evaluation of goodwill for impairment was expected to occur in the fourth quarter of 2017; however, we experienced an impairment triggering event as of September 30, 2017 and implemented the new guidance as part of the impairment evaluation. See the footnote titled Goodwill for a detailed description of the results of our impairment testing.

Recently Issued Accounting Standards

In May 2014, the 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
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2017
(unaudited)


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. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period; we are adopting the standard effective January 1, 2018. The revenue standard can be adopted under the full retrospective method or modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard will have on our consolidated financial statements, we are performing a comprehensive review of our significant revenue streams. The focus of this review includes, 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 transaction price. We are also reviewing our current accounting policies, procedures, and controls with respect to these contracts and arrangements to determine what changes, if any, may be required by the adoption of the revenue standard. We have determined that we will adopt the standard under the modified retrospective method. We have not made a complete determination regarding the impact that the adoption will have on our consolidated financial statements as of the time of this filing.

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. 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. We are currently evaluating the impact these changes may have on our consolidated financial statements.

In August 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements.

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 a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted 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. We are currently evaluating the impact these changes may have on our consolidated financial statements.

In January 2017, the FASB issued an accounting update clarifying the definition of a business, with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This guidance is to be applied using a prospective method and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements.

In May 2017, the FASB issued an accounting update clarifying when to account for a change to the terms or conditions of a share-based payment award as a modification. The guidance is effective for fiscal years beginning on or after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Adoption of this standard is not expected to have a significant impact on our condensed consolidated financial statements.



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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2017
(unaudited)


NOTE 32 - BUSINESS COMBINATION


Delaware Basin Acquisition. On December 6, 2016,In January 2020, we closed onmerged with SRC Energy Inc. (“SRC”) in a transaction valued at $1.7 billion, inclusive of SRC’s net debt (the “SRC Acquisition”). SRC was an acquisition which was accounted for as a business combination.independent oil and natural gas company engaged in the exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in Weld County, Colorado. The acquisition consistedadded approximately 83,000 net acres which are located on large, contiguous acreage blocks in the core of the purchase of stock of an entity and assets of other entities under common control. The transaction was for the purchase ofWattenberg Field.

Upon closing, we issued approximately 57,900 net acres, approximately 30 completed and producing wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion, after preliminary post-closing adjustments. The total consideration to sellers was comprised of approximately $946.0 million in cash, including the payment of $40.0 million of debt of the sellers at closing and other purchase price adjustments, and 9.438.9 million shares of our common stock valued at approximately $690.7 million atto SRC shareholders and holders of SRC equity awards, reflecting the timeissuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the acquisition closed. The purchase accounting forcancellation of outstanding SRC equity awards pursuant to the entity of which we acquired the stock reflected oil and gas assets that did not receive fair value step-upterms of the tax basis. As a result, a significant deferred income tax liability was calculated based onmerger agreement that we entered into with SRC. We finalized the acquired allocated fair value of the assets in excess of the tax basis of assets inside the entity. This calculation resulted in approximately $375.0 million of non-cash basis needing to be allocated to the acquired assets. No deferred tax liability was established for the calculated goodwill as the goodwill did not qualify as tax goodwill.

The final fair value allocation of the assets acquired and liabilities assumed in the acquisition are presented below and include customary post-closing adjustments. The most significant item to be completed during the final purchase price allocation in the third quarteron December 31, 2020, and we recognized total transaction costs of 2017 was the final allocation of value to the unproved oil and gas properties associated with the acquired acreage. Adjustments to the preliminary purchase price primarily stem from additional information we obtained about facts and circumstances that existed at the acquisition date that impact the underlying value of certain assets acquired and liabilities assumed, including detailed lease terms, location of the acreage, and intent to develop the acreage as of the date of closing. There were a significant number of leases acquired with complex lease terms and evaluation of these terms and the timing of the lease expirations impacted the manner in which the final purchase price was allocated. Our final determination of the value of goodwill has been adjusted for all post-closing adjustments.

The details of the final purchase price and the allocation of the purchase price$19.9 million for the transaction, are presented below (in thousands):year ended December 31, 2020.
6
 September 30, 2017
Acquisition costs: 
       Cash, net of cash acquired$905,962
       Retirement of seller's debt40,000
  Total cash consideration945,962
        Common stock, 9.4 million shares690,702
        Other purchase price adjustments426
  Total acquisition costs$1,637,090
  
Recognized amounts of identifiable assets acquired and liabilities assumed: 
Assets acquired: 
       Current assets$6,401
       Crude oil and natural gas properties - proved216,000
       Crude oil and natural gas properties - unproved1,697,000
       Infrastructure, pipeline, and other33,153
       Construction in progress12,323
       Goodwill75,121
Total assets acquired2,039,998
Liabilities assumed: 
       Current liabilities(24,496)
       Asset retirement obligations(3,705)
       Deferred tax liabilities, net(374,707)
Total liabilities assumed(402,908)
Total identifiable net assets acquired$1,637,090
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



The following table details our final purchase price, valuation and allocation of the purchase price to the assets acquired and liabilities assumed as a result of the SRC Acquisition:

(in thousands)
Consideration:
Cash$40 
Retirement of seller's credit facility166,238 
Total cash consideration166,278 
Common stock issued1,009,015 
Shares withheld in lieu of taxes6,299 
Total consideration$1,181,592 
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Current assets$145,792 
Properties and equipment, net - proved1,613,674 
Properties and equipment, net - unproved109,615 
Properties and equipment, net - other16,242 
Deferred tax asset189,311 
Other assets11,810 
Total assets acquired2,086,444 
Liabilities assumed:
Current liabilities(253,967)
Senior notes(555,500)
Asset retirement obligations(42,417)
Other liabilities(52,968)
Total liabilities assumed(904,852)
Total identifiable net assets acquired$1,181,592 

This acquisition was accounted for under the acquisition method of accounting for business combinations. 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 and assumptions to the valuation of proved and unproved crude oil and natural gas properties include estimates of reserves,reserve volumes, 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. Within the unproven properties, the allocationrate of the value to the underlying leases also required significant judgment and was 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.10 percent. These inputs require significant judgments and estimates by management at the time of the valuation and were the most sensitive and subject to change.valuation.

This acquisition was accounted for under the acquisition method. Accordingly, we conducted assessments of 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.

Goodwill. Goodwill was calculated as the excess of the purchase price over the fair value of net assets acquired, including the additional value resulting from the creation of the deferred tax liability, and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired were the acquisition of an element of a workforce and the expected value from operations of the Delaware Basin acquisition to be derived in the future, such as production from future development of additional producing zones. The amount of the final goodwill that was recorded in the third quarter of 2017 related to the Delaware Basin acquisition was $75.1 million and was higher than the initial estimated amount recorded as of December 31, 2016, primarily related to finalization of the aggregate acreage position acquired and the related lease terms and a final settlement with the sellers in connection with a revised valuation of certain acquired leases and the retirement of estimated environmental remediation liabilities. Any value assigned to goodwill was not expected to be deductible for income tax purposes.


The following table presentsresults of operations for the changes in goodwill fromSRC Acquisition since the preliminary allocation at December 31, 2016,closing date have been included on our condensed consolidated financial statements for the three and the final allocation determined during the quarternine months ended September 30, 2017:2020 and include approximately $82.0 million and $233.8 million, respectively, of total revenue, and $20.7 million and $19.3 million loss from operations, respectively.

7
 Amount
 (in thousands)
  
Preliminary purchase price allocation$62,041
Adjustments13,080
Final purchase price allocation$75,121

See the footnote titled Goodwill for the details regarding the impairment of goodwill as of September 30, 2017.

NOTE 4 - PENDING ACQUISITION AND ACREAGE EXCHANGES

Pending Acquisition. In September 2017, we entered into an acquisition agreement to acquire certain assets from Bayswater Exploration & Production, LLC ("Bayswater") and certain related parties, pursuant to which, subject to the terms and conditions of the agreement, we have agreed to acquire approximately 8,300 net acres, 30 operated drilled uncompleted wells ("DUCs"), and an estimated 240 gross drilling locations, for approximately $210 million in cash, subject to certain pre- and post-closing adjustments. We plan to turn-in-line 18 of these DUCs at approximately year-end 2017, with the completion costs expected to be treated as an increase to the purchase price. Upon executing the purchase and sale agreement, we paid a $21 million deposit toward the purchase price into an escrow account, which is included in other assets on our September 30, 2017 condensed consolidated balance sheet. Assuming all conditions required for closing are met, the acquisition is expected to close in December 2017 and is expected to be funded by a combination of available cash and debt.

Pending Acreage Exchanges. In September 2017, we entered into an acreage exchange transaction to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we will exchange leasehold acreage with some limited in-process development wells. Upon closing, we expect to receive approximately 11,700 net acres in exchange for approximately 12,100 net acres with minimal cash exchanged between the parties. The difference in net acres is
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



primarily due to variances in working and net revenue interests.Pro Forma Information. The acreage exchange is expected to close in the fourth quarter of 2017; however, there can be no assurance that conditions to closing will be satisfied.

In June 2017, we entered into an acreage exchange transaction that also involves the consolidation of certain acreage positions in the core areafollowing unaudited pro forma financial information represents a summary of the Wattenberg Field. Pursuantconsolidated results of operations for the nine months ended September 30, 2020, assuming the acquisition had been completed as of January 1, 2020. The information below reflects certain nonrecurring pro forma adjustments that were directly related to the transaction, we will exchange leasehold acreage with some limited in-process development wells. Upon closing, we estimatebusiness combination based on available information and certain assumptions that we will receivebelieve are reasonable, including (i) the Company's common stock issued to convert SRC’s outstanding shares of common stock and the cancellation of equity awards, (ii) the depletion of SRC’s fair-valued proved oil and gas properties using the successful efforts method of accounting and (iii) the estimated tax impacts of the pro forma adjustments, if any. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company and SRC totaling approximately 3,900 net acres in exchange$38.0 million for approximately 4,100 net acres with minimal cash exchanged between the parties.nine months ended September 30, 2020. The difference in net acrespro forma financial information is primarily due to variances in working and net revenue interests. This acreage exchange is also expected to close innot necessarily indicative of the fourth quarter 2017; however, there can be no assuranceresults of operations that conditions to closing will be satisfied.would have been achieved if the acquisition had been effective as of these dates, or of future results.


Nine Months Ended September 30, 2020
Total revenue$1,082,003 
Net income (loss)(677,636)
Earnings (loss) per share:
Basic$(6.79)
Diluted(6.79)


8
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



NOTE 53 - EXPLORATION, GEOLOGIC, AND GEOPHYSICAL EXPENSEREVENUE RECOGNITION


Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the periods presented:

Three Months Ended September 30,Nine Months Ended September 30,
Revenue by Commodity and Operating Region20212020Percent Change20212020Percent Change
(in thousands)
Crude oil
Wattenberg Field$341,822 $183,420 86 %$869,336 $483,608 80 %
Delaware Basin80,751 42,591 90 %177,587 107,347 65 %
Total$422,573 $226,011 87 %$1,046,923 $590,955 77 %
 Natural gas
Wattenberg Field$116,263 $39,759 192 %$287,949 $109,279 164 %
Delaware Basin19,207 2,140 *38,970 3,183 *
Total$135,470 $41,899 223 %$326,919 $112,462 191 %
NGLs
Wattenberg Field$121,837 $38,871 213 %$283,119 $86,875 226 %
Delaware Basin23,256 8,139 186 %47,435 18,864 151 %
Total$145,093 $47,010 209 %$330,554 $105,739 213 %
Crude oil, natural gas and NGLs
Wattenberg Field$579,922 $262,050 121 %$1,440,404 $679,762 112 %
Delaware Basin123,214 52,870 133 %263,992 129,394 104 %
Total$703,136 $314,920 123 %$1,704,396 $809,156 111 %
_____________
* Percent change is not meaningful.

Contract Assets.Contract assets include material contributions in aid of construction, which are common in purchase and processing agreements with the midstream service providers that are our customers. The intent of the payments is primarily to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are included in other assets on the condensed consolidated balance sheets. The contract assets are 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 major componentschanges in carrying amounts of exploration, geologic,the contract assets associated with our crude oil, natural gas and geophysical expense:

 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in thousands)
        
Exploratory dry hole costs$41,187
 $—
 $41,187
 $—
Geological and geophysical costs, including seismic purchases463
 —
 1,790
 —
Operating, personnel and other258
 241
 918
 688
Total exploration, geologic, and geophysical expense$41,908
 $241
 $43,895
 $688
        

Exploratory dry hole costs. DuringNGLs sales revenue for the three and nine months ended September 30, 2017, two exploratory dry hole wells, associated lease costs, and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.2 million. The conclusion to expense these items was due to the conclusion that the acreage on which these wells were drilled was exploratory in nature and, following drilling, the lack of hydrocarbon production necessary for the wells to be deemed economically viable.2021:

(in thousands)
Beginning balance$25,872 
Reduction to additions previously recognized(2,574)
Amortized as a reduction to crude oil, natural gas and NGLs sales(2,181)
Ending balance$21,117 
NOTE 6 - PROPERTIES AND EQUIPMENT AND ASSETS HELD-FOR-SALE

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


9
 September 30, 2017 December 31, 2016
 (in thousands)
Properties and equipment, net:   
Crude oil and natural gas properties   
Proved$3,759,501
 $3,499,718
Unproved1,559,717
 1,874,671
Total crude oil and natural gas properties5,319,218
 5,374,389
Infrastructure, pipeline, and other104,568
 62,093
Land and buildings10,714
 6,392
Construction in progress177,341
 122,591
Properties and equipment, at cost5,611,841
 5,565,465
Accumulated DD&A(1,729,141) (1,562,471)
Properties and equipment, net$3,882,700
 $4,002,994
    

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

 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in thousands)

       
Impairment of unproved properties$252,623
 $338
 $282,188
 $2,391
Amortization of individually insignificant unproved properties117
 595
 311
 681
Impairment of crude oil and natural gas properties
252,740
 933
 282,499
 3,072
Land and buildings—
 —
 —
 3,032
Total impairment of properties and equipment$252,740
 $933
 $282,499
 $6,104

During the three months ended September 30, 2017, we recorded a charge related to two exploratory dry holes we had drilled in the western area of our Culberson County acreage in the Delaware Basin, as referenced previously.  We then assessed the impact of the dry holes and various factors related thereto, including (i) the operational and geologic data obtained, (ii) the
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



NOTE 4 - FAIR VALUE MEASUREMENTS
current increased cost environment for drilling and completion services in
Recurring Fair Value Measurements

Derivative Financial Instruments. We measure the Delaware Basin, (iii)fair value of our decreased future commodity price outlook, and (iv)derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the termscontractual price of the related lease agreements.  Based on the results of this assessment, we concluded that the underlying geologicposition, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors and nonperformance risk. Nonperformance risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage.  Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during the third quarter of 2017.  The amount of the impairment of these unproved properties was based on the value assigned to individual lease acres in the final purchase price allocation of the business combination.  This allocation had included the consideration paid to the sellers, includingconsiders the effect of our credit standing on the non-cash impact fromfair value of derivative liabilities and the deferred tax liability createdeffect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default exchange rates and the duration of each outstanding derivative position. We validate our fair value measurement by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions and reviewing counterparty statements and other supporting documentation.

Our crude oil and natural gas fixed-price exchanges are included in Level 2. Our collars are included in Level 3. Our basis exchanges are included in Level 2 and Level 3. 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 the timefair value on a recurring basis as of the acquisition. Due to the aforementioned events and circumstances in the third quarter of 2017, we evaluated our proved property for possible impairment and concluded that these assets were not impaired during the period.dates indicated:

September 30, 2021December 31, 2020
Condensed Consolidated Balance Sheet Line ItemSignificant Other
Observable
Inputs
(Level 2)		Significant
Unobservable
Inputs
(Level 3)		TotalSignificant Other
Observable
Inputs
(Level 2)		Significant
Unobservable
Inputs
(Level 3)		Total
(in thousands)
Derivative assets
CurrentFair value of derivatives$523 $7,036 $7,559 $36,580 $12,289 $48,869 
Non-currentFair value of derivatives90 12,652 12,742 315 9,250 9,565 
Total$613 $19,688 $20,301 $36,895 $21,539 $58,434 
Derivative liabilities
CurrentFair value of derivatives$305,677 $148,901 $454,578 $76,420 $21,732 $98,152 
Non-currentFair value of derivatives104,190 29,441 133,631 28,125 8,234 36,359 
Total$409,867 $178,342 $588,209 $104,545 $29,966 $134,511 
Classification of Assets as Held-for-Sale. During the third quarter of 2017, as part of our plan to divest the Utica Shale properties, we engaged an investment banking group and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification during the third quarter of 2017.

The following table presents balance sheet data related toa reconciliation of our Level 3 assets held-for-sale, which include the Utica Shale properties, field office facilities, and a parcel of land that are being marketed for sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities that are expected to be assumed by the purchasers:    measured at fair value:

Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
(in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period$(117,985)$26,958 $(8,427)$8,414 
Changes in fair value included on condensed consolidated statements of operations line item:
Commodity price risk management gain (loss), net(87,036)(21,521)(214,556)32,840 
Settlements included on condensed consolidated statement of operations line items:
Commodity price risk management gain (loss), net46,368 (14,652)64,330 (50,469)
Fair value of Level 3 instruments, net asset (liability) end of period$(158,653)$(9,215)$(158,653)$(9,215)
Net change in fair value of Level 3 unsettled derivatives included on condensed consolidated statements of operations line item:
Commodity price risk management gain (loss), net$(78,786)$(13,171)$(210,430)$9,466 

10
 September 30, 2017 December 31, 2016
 (in thousands)
Assets   
  Properties and equipment, net$41,983
 $5,272
Total assets$41,983
 $5,272
    
Liabilities   
  Asset retirement obligation$499
 $—
Total liabilities$499
 $—
    
Net assets$41,484
 $5,272


NOTE 7 - GOODWILL

The final goodwill that resulted from the purchase price allocation of the assets acquired in the Delaware Basin was determined to be $75.1 million. With the creation of goodwill from this transaction, we expected to perform our evaluation of goodwill for impairment annually in the fourth quarter. However, primarily due to a combination of increases in per well development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin since the time of the acquisition, in conjunction with our lower future commodity price outlook, we determined a triggering event had occurred in the quarter ended September 30, 2017. In addition to the factors mentioned above, we also considered our recent impairments of certain unproven leasehold costs, and the impact of these items on our internal expectations for acceptable rates of return. We evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill asset group, which we define as the Delaware Basin, to the carrying value. We determined the fair value of the goodwill at September 30, 2017 by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value was based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. The quantitative test resulted in a determination that a full impairment charge of $75.1 million was required; therefore, the charge was recorded in the quarter ended September 30, 2017.

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



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 the financial statements.

Nonrecurring Fair Value Measurement

Acquisitions and Impairment of Long-lived Assets. We measure fair value using inputs that are not observable in the market, and are therefore designated as Level 3 within the valuation hierarchy, on a nonrecurring basis for any acquired assets or businesses and to review our proved and unproved crude oil and natural gas properties for possible impairment.
Asset Retirement Obligations. We measure the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy.

Other Financial Instruments

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

Long-term Debt. The portion of our long-term debt related to our revolving credit facility approximates fair value, as the applicable interest rates are variable and reflective of market 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 or dealer quotes, 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 the dates indicated:

September 30, 2021December 31, 2020
Nominal InterestEstimated Fair ValuePercent of ParEstimated Fair ValuePercent of Par
(in millions)(in millions)
Senior Notes:
2021 Convertible Notes (1)
1.125 %$— — %$196.2 98.1 %
2024 Senior Notes6.125 %406.0 101.5 %410.8 102.7 %
2025 Senior Notes6.25 %103.9 101.5 %102.8 100.5 %
2026 Senior Notes5.75 %780.8 104.1 %775.5 103.4 %
____________
(1) Our 2021 Convertible Notes were redeemed and retired on September 15, 2021.

NOTE 85 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS


Objective and Strategy. 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 and natural gas and propane, which is an element of our NGLs, we enter into commodity derivative contracts such as collars, fixed-price exchanges and basis protection exchanges, 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 do not enter into derivative contracts for speculative or trading purposes.

We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. As of September 30, 2017,2021, we had derivative instruments which were comprised of collars, fixed-price swaps, and basis protection swaps, in place for a portion of our anticipated 2017 and 2018 production for a total of 14,337 MBbls of crude oil, 69,715 BBtu of natural gas, and 412 MBbls of propane.in 2021 through 2024. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount.

We have not elected to designate any of our derivative instruments as cash flow hedges, and 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:
11
     Fair Value
Derivative instruments: Condensed consolidated balance sheet line item September 30, 2017 December 31, 2016
     (in thousands)
Derivative assets:Current      
 Commodity derivative contracts Fair value of derivatives $19,042
 $8,490
 Basis protection derivative contracts Fair value of derivatives 3,874
 301
     22,916
 8,791
 Non-current      
 Commodity derivative contracts Fair value of derivatives 3,942
 1,123
 Basis protection derivative contracts Fair value of derivatives 663
 1,263
     4,605
 2,386
Total derivative assets   $27,521
 $11,177
        
Derivative liabilities:Current      
 Commodity derivative contracts Fair value of derivatives $25,895
 $53,565
 Basis protection derivative contracts Fair value of derivatives 92
 30
     25,987
 53,595
 Non-current      
 Commodity derivative contracts Fair value of derivatives 7,244
 27,595
 Basis protection derivative contracts Fair value of derivatives 17
 —
     7,261
 27,595
Total derivative liabilities   $33,248
 $81,190

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



Effect of Derivative Instruments on the Condensed Consolidated Statements of Operations. The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations:

Three Months Ended September 30,Nine Months Ended September 30,
Condensed Consolidated Statement of Operations Line Item2021202020212020
(in thousands)
Commodity price risk management gain (loss), net
Net settlements$(129,571)$66,895 $(215,357)$227,513 
Net change in fair value of unsettled derivatives(88,107)(134,956)(491,830)18,338 
Total commodity price risk management gain (loss), net$(217,678)$(68,061)$(707,187)$245,851 

  Three Months Ended September 30, Nine Months Ended September 30,
Condensed consolidated statement of operations line item 2017 2016 2017 2016
  (in thousands)
Commodity price risk management gain, net        
Net settlements $9,585
 $47,728
 $22,151
 $167,859
Net change in fair value of unsettled derivatives (61,763) (28,331) 64,307
 (230,207)
Total commodity price risk management gain, net $(52,178) $19,397
 $86,458
 $(62,348)
         

Net settlementsCommodity Derivative Contracts. As of commodity derivatives decreased for the three and nine months ended September 30, 2017 as compared to2021, we had the three and nine months ended following outstanding derivative contracts. When aggregating multiple contracts, the weighted-average contract price is presented:
 CollarsFixed-Price Swaps 
Commodity/ Index/
Maturity Period
Quantity
(Crude oil -
MBbls
Natural Gas - BBtu)
Weighted-Average
Contract Price
Quantity
(Crude Oil - MBbls
Gas and Basis-
BBtu)
Weighted-
Average
Contract
Price
Fair Value
September 30, 2021
(in thousands)
FloorsCeilings
Crude Oil
NYMEX
20211,251 $38.01 $49.29 2,488 $41.89 $(112,693)
20224,272 51.26 63.33 6,744 44.42 (214,207)
20231,200 55.00 65.58 5,202 56.55 (41,739)
2024— — — 600 59.05 (892)
Total Crude Oil6,723 15,034 $(369,531)
Natural Gas
NYMEX
202118,300 2.51 2.92 7,950 2.40 (82,363)
202217,400 2.50 2.89 33,600 2.70 (84,484)
2023— — — 30,398 2.68 (22,515)
Total Natural Gas35,700 71,948 (189,362)
Basis Protection - Natural Gas
CIG
202126,250 (0.44)(3,443)
202251,000 (0.26)(4,775)
202326,438 (0.26)(797)
Total Basis Protection - Natural Gas103,688 (9,015)
Commodity Derivatives Fair Value$(567,908)

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016.  We2021
(Unaudited)

Subsequent to September 30, 2021, we entered into agreements for the following commodity derivative positions covering our crude oil and natural gas production:

 CollarsFixed-Price Swaps
Commodity/ Index/
Maturity Period
Quantity
(Crude oil -
MBbls
Natural Gas - BBtu)
Weighted-Average
Contract Price
Quantity
(Crude oil -
MBbls
Natural Gas - BBtu)
Weighted-
Average
Contract
Price
FloorsCeilings
Crude Oil
NYMEX
20221,200 $60.00 $81.60 — $— 
20231,575 55.00 73.32 30061.52
2024225 55.0075.1130061.52
Natural Gas
NYMEX
202218,060 $3.75 $6.60 — $— 
20234,020 3.00 4.42 — — 
Basis Protection
CIG
2022— $— $— 18,060 $(0.22)
2023— — — 4,020 (0.29)

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet.The balance sheet line items and fair value amounts of our derivative instruments that settled throughout 2016 prior to commodity prices becoming depressedare disclosed in late 2014.  Substantially all of these higher-value agreements settled by the end of 2016.  Net settlements for the three and nine months ended September 30, 2017 reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices.  Based on forward strip pricing at September 30, 2017, we expect that settlements will continue to be substantially lower in 2017 on a relative basis as compared to those in 2016.Note 4 - Fair Value Measurements.


All of our0Our 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.


The following table reflects the impact of netting agreements on gross derivative assets and liabilities:
As of September 30, 2017 Derivative instruments, recorded in condensed consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net
  (in thousands)
Asset derivatives:      
Derivative instruments, at fair value $27,521
 $(15,010) $12,511
       
Liability derivatives:      
Derivative instruments, at fair value $33,248
 $(15,010) $18,238
       
As of December 31, 2016 Derivative instruments, recorded in condensed consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net
  (in thousands)
Asset derivatives:      
Derivative instruments, at fair value $11,177
 $(10,930) $247
       
Liability derivatives:      
Derivative instruments, at fair value $81,190
 $(10,930) $70,260
       

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2017
(unaudited)


NOTE 9 - 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 liabilityliabilities 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:dates indicated:

As of September 30, 2021Total Gross Amount Presented on the Balance SheetEffect of Master Netting AgreementsTotal Net Amount
(in thousands)
Derivative assets:
Derivative instruments, at fair value$20,301 $(20,301)$— 
Derivative liabilities:
Derivative instruments, at fair value$588,209 $(20,301)$567,908 
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. Our collars and propane fixed-price swaps are included in Level 3. Our basis swaps are included in Level 2 and Level 3. 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:

 September 30, 2017 December 31, 2016
 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)
Assets:           
Total assets$24,553
 $2,968
 $27,521
 $6,350
 $4,827
 $11,177
Total liabilities(23,811) (9,437) (33,248) (66,789) (14,401) (81,190)
Net asset (liability)$742
 $(6,469) $(5,727) $(60,439) $(9,574) $(70,013)
            
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2017
(unaudited)


The following table presents a reconciliation of our Level 3 assets measured at fair value:

  Three Months Ended September 30, Nine Months Ended September 30,
  2017 2016 2017 2016
  (in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period $8,619
 $27,375
 $(9,574) $91,288
Changes in fair value included in condensed consolidated statement of operations line item:        
Commodity price risk management gain (loss), net (14,075) 4,234
 8,547
 (16,023)
Settlements included in condensed consolidated statement of operations line items:        
Commodity price risk management gain (loss), net (1,013) (15,587) (5,442) (59,243)
Fair value of Level 3 instruments, net asset end of period $(6,469) $16,022
 $(6,469) $16,022
         
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 $(8,711) $(2,240) $(583) $(8,273)
         

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 crude oil and natural gas properties and goodwill 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 fair value of the goodwill is determined using either a qualitative method or a quantitative method, both of which utilize market data, a Level 3 input, in the derivation of the value estimation.
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 September 30, 2017.
  Estimated Fair Value Percent of Par
  (in millions)  
Senior notes:   
 2021 Convertible Notes$196.3
 98.1%
 2022 Senior Notes521.9
 104.4%
 2024 Senior Notes412.5
 103.1%

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.
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2017
(unaudited)



Concentration of Risk

Derivative Counterparties. A portion of our liquidity relates toOur 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 creditthe risk of nonperformancenon-performance 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. An insignificant portion of our commodity derivative instruments may be with other counterparties. 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 September 30, 2017, taking into account the estimated likelihood of nonperformance.2021; however, this determination may change.


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 September 30, 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.
13


NOTE 10 - NOTE RECEIVABLE

In October 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. The interest was to be paid quarterly, in arrears and at the option of the issuer could be paid-in-kind (“PIK Interest”). Any such PIK Interest would be subject to the then current interest rate.

We regularly analyzed the Promissory Note for evidence of collectability, 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. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Promissory Note and began accounting for the interest on the Promissory Note under the cash basis method.

We performed this analysis as of March 31, 2017 and evaluated preliminary 2016 year-end financial statements of the note issuer which were available at such time, related information about the operations of the issuer, and existing market conditions for natural gas. Based upon this evaluation, it was determined that collection of the Promissory Note and the PIK Interest continued to be doubtful and the full valuation allowance on the Promissory Note remained appropriate as of that date. This evaluation assumed that repayment of the Promissory Note would be made exclusively from the existing operations of the issuer of the Promissory Note based on the latest available information.

In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately $40.2 million in cash. The sales agreement transferred all of our legal rights to collect from the issuer of the Promissory Note. Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during the second quarter of 2017.

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



NOTE 116 - INCOME TAXESPROPERTIES AND EQUIPMENT, NET

We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual annual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective income tax rate, adjusted for the effect of discrete items.


The effective income tax rates forfollowing table presents the threecomponents of properties and nine months ended September 30, 2017equipment, net of accumulated depreciation, depletion and amortization (“DD&A”) as of the dates indicated:
September 30, 2021December 31, 2020
(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved$8,135,626 $7,523,639 
Unproved338,668 350,677 
Total crude oil and natural gas properties8,474,294 7,874,316 
Equipment and other64,343 65,027 
Land and buildings19,978 24,299 
Construction in progress368,808 523,550 
Properties and equipment, at cost8,927,423 8,487,192 
Accumulated DD&A(4,101,086)(3,627,993)
Properties and equipment, net$4,826,337 $4,859,199 

Impairment of Oil and Gas Properties. There were 29.5 percent and 25.8 percent benefit on loss, respectively, compared to 34.0 percent and 37.1 percent benefit on loss for the three and nine months ended September 30, 2016. The mostno significant elementimpairment charges recognized related to the decrease in the effective income tax rate was the impact from the $75.1 million impairment of the goodwill in the quarter ended September 30, 2017. This goodwill did not have an associated deferred tax liability at the time it was created, therefore, no deferred tax benefit was realized upon the impairment of the goodwill. The effective income tax rates for the threeour proved and nine months ended September 30, 2017, are based upon a full year forecasted tax benefit on loss. In addition to the impact from the goodwill impairment, the effective income tax rate for the three months ended September 30, 2017 includes discrete income tax benefits of $0.8 million for additional deductions and credits claimed on the filed 2016 federal and state income tax returns. The effective income tax rate for the nine months ended September 30, 2017 includes discrete income tax benefits of $1.8 million relating to the excess income tax benefit recognized with the vesting of stock awards and $0.8 million for additional deductions and credits claimed on the filed 2016 federal and state tax returns. These discrete tax benefitsunproved properties during the three and nine months ended September 30, 2017 resulted2021. In the first quarter of 2020, the significant decline in crude oil prices in addition to the ongoing effects of the COVID-19 pandemic were considered a 0.2 percenttriggering event that required us to assess our crude oil and 0.9 percent increasenatural gas properties for possible impairment. As a result of our assessment, we recorded impairment expense of $881.1 million to our effective income tax rates.proved and unproved properties.

Proved Properties. Of the total impairment expense recognized in the first quarter of 2020, approximately $753.0 million was related to our Delaware Basin proved properties. These impairment charges represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. We anticipateestimated the potential for increased periodic volatility infair value of proved crude oil and natural gas properties using valuation techniques that convert future effective income tax rates fromcash flows to a single discounted amount, a level 3 input. Significant inputs and assumptions to the impactvaluation of stock-based compensation tax deductions as they are treated as discrete tax items.

The effective income tax ratesproved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices,and a discount rate of17 percent, which was based on a weighted-average cost of capital for the three and nine months ended September 30, 2016, were based upon a full year forecasted income tax benefit on loss and were greater thanarea where the statutory federal income tax rate, primarily due to state income taxes and percentage depletion, partially offset by nondeductible officers’ compensation and nondeductible lobbying expenses. There were no significant discrete income tax items recordedassets are located.

Unproved Properties. We recognized approximately $127.3 million of impairment charges for our unproved properties in the Delaware Basin during the three and nine months ended September 30, 2016.

As of September 30, 2017, there is no liability for unrecognized income tax benefits. AsMarch 31, 2020. These impairment charges were recognized based on the fair value of the dateproperties, a Level 3 input. The fair value is estimated based on a review of this report,our current drilling plans, estimated future cash flows for probable well locations and expected future lease expirations, primarily in areas where we are current with our income tax filingshave no development plans.
Suspended Well Costs. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in all applicable state jurisdictionsproperties and are not currently under any state income tax examinations. We continue to voluntarily participate in the Internal Revenue Service's Compliance Assurance Programequipment for the 2016 and 2017 tax years, and received final acceptance of our 2015 federal income tax return and partial acceptance of the recently filed 2016 federal income tax return that is now going through the IRS CAP post-filing review process.periods presented:

Nine Months Ended September 30, 2021Year Ended December 31, 2020
(in thousands, except for number of wells)
Beginning balance$7,459 $16,078 
Additions to capitalized exploratory well costs pending the determination of proved reserves6,090 11,770 
Reclassifications to proved properties(13,549)(20,389)
Ending balance$— $7,459 
Number of wells pending determination at period-end—2

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



NOTE 12 - LONG-TERM DEBT

Long-term debt consistedAs of the following as of:
 September 30, 2017 December 31, 2016
 (in thousands)
Senior notes:   
1.125% Convertible Notes due 2021:   
Principal amount$200,000
 $200,000
Unamortized discount(32,153) (37,475)
Unamortized debt issuance costs(3,859) (4,584)
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs163,988
 157,941
    
7.75% Senior Notes due 2022:   
Principal amount500,000
 500,000
Unamortized debt issuance costs(5,602) (6,443)
7.75% Senior Notes due 2022, net of unamortized debt issuance costs494,398
 493,557
    
6.125% Senior Notes due 2024:   
Principal amount400,000
 400,000
Unamortized debt issuance costs(6,815) (7,544)
6.125% Senior Notes due 2024, net of unamortized debt issuance costs393,185
 392,456
    
Total senior notes1,051,571
 1,043,954
    
Revolving credit facility—
 —
Total long-term debt, net of unamortized discount and debt issuance costs$1,051,571
 $1,043,954
Senior Notes

2021 Convertible Notes. In September 2016, we issued $200 million of 1.125% convertible notes due 2021 (the "2021 Convertible Notes") in a public offering. The maturity for the payment of principal is September 15, 2021. Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September 15. The conversion stock 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 inDecember 31, 2020, our net capitalized exploratory well costs associated with the issuance of the 2021 Convertible Notesthat have been capitalized for a period greater than one year were $7.5 million. During the three months ended September 30, 2021, both exploratory wells were determined to be successful producing wells and were reclassified into proved properties. We have no remaining exploratory wells pending determination as debt issuance costs. As of September 30, 2017,2021.

NOTE 7 - ACCOUNTS RECEIVABLE, OTHER ACCRUED EXPENSES AND OTHER LIABILITIES

Accounts Receivable. The following table presents the unamortized debt discount will be amortized over the remaining contractual term to maturitycomponents of accounts receivable, net of allowance for doubtful accounts, as of the 2021 Convertible Notes using an effective interest ratedates indicated:
September 30, 2021December 31, 2020
(in thousands)
Crude oil, natural gas and NGLs sales$343,022 $178,147 
Joint interest billings21,257 35,396 
Other11,104 37,471 
Allowance for doubtful accounts(6,772)(6,763)
Accounts receivable, net$368,611 $244,251 
Other Accrued Expenses. The following table presents the components of 5.8 percent.other accrued expenses as of the dates indicated:
September 30, 2021December 31, 2020
(in thousands)
Employee benefits$24,106 $23,304 
Asset retirement obligations33,875 33,933 
Environmental expenses11,992 10,139 
Operating and finance leases7,532 7,986 
Other8,015 6,353 
Other accrued expenses$85,520 $81,715 
Upon conversion,
Other Liabilities. The following table presents the 2021 Convertible Notes may be settled, at our sole election, in sharescomponents of other liabilities as of the dates indicated:
September 30, 2021December 31, 2020
(in thousands)
Deferred midstream gathering credits$162,112 $168,478 
Deferred oil gathering credits16,583 18,090 
Production taxes87,170 65,592 
Operating and finance leases7,760 10,763 
Other751 1,111 
Other liabilities$274,376 $264,034 

Deferred Midstream Gathering Credits. In the second quarter of 2019, concurrent with the sale of our common stock, cash, or a combinationDelaware Basin midstream assets, we entered into an agreement with each of cash and sharesthe purchasers pursuant to which we dedicated the gathering of certain of our common stock. We have initially elected a combination settlement methodproduction and all water gathering and disposal volumes in the Delaware Basin. The terms of these agreements range from 15 to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes22 years. The acreage dedication agreements resulted in initial cash and to settle the excess conversion value, if any, in shares of our common stock, as well as cash in lieu of fractional shares.
2022 Senior Notes. In October 2012, we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”). The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15. Approximately $11.0 million in costs associated with the issuance of the 2022 Senior Notes have been capitalized as debt issuance costsreceipts and are being amortized as interest expense over the life of the notes using the effective interest method.on a units-of-production basis. The amortization rates are assessed on an annual basis for changes in estimated future production.


2024 Senior Notes.  Deferred Oil Gathering Credits.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 that2018, we entered into withan agreement that dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider’s gathering lines and extends the term of the agreement through December 2029. The acreage dedication agreement resulted in an initial purchasers when we issued the 2024cash receipt and is being amortized on a units-of-production basis. The amortization rates are assessed on an annual basis for changes in estimated future production.

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



The following table presents the amortization charges recognized on the condensed consolidated statements of operations for the periods indicated:
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,
Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
(in thousands)
Crude oil, natural gas and NGLs sales$— $— $— $368 
Transportation, gathering and processing expense2,014 2,038 5,343 4,499 
Lease operating expense732 686 1,817 1,458 

NOTE 8 - LONG-TERM DEBT

Long-term debt, net of unamortized discounts, premiums, 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 in arrears on March 15 and September 15. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as debt issuance costs totaling $9.1 million and are being amortized$17.8 million as interest expense over the life of the notes using the effective interest method.

In January 2017, pursuant to the filing of supplemental indentures for the 2021 Convertible Notes, 2022 Senior Notes, and the 2024 Senior Notes (collectively, the "Notes"), our wholly-owned subsidiary, PDC Permian, Inc. became a guarantor of our obligations under the Notes. Accordingly, condensed consolidating financial information for PDC and PDC Permian, Inc. is presented in the footnote titled Subsidiary Guarantor.

As of September 30, 2017, we were in compliance with all covenants related to2021 and December 31, 2020, respectively, consists of the Notes, and expect to remain in compliance throughout the next 12-month period.following:


September 30, 2021December 31, 2020
(in thousands)
Revolving credit facility due May 2023$— $168,000 
1.125% Convertible Notes due September 2021— 193,014 
6.125% Senior Notes due September 2024397,103 396,368 
6.25% Senior Notes due December 2025103,081 103,204 
5.75% Senior Notes due May 2026743,051 741,976 
Total debt, net of unamortized discount, premium and debt issuance costs1,243,235 1,602,562 
Less: Current portion of long-term debt— 193,014 
Total long-term debt$1,243,235 $1,409,548 
Revolving Credit Facility


RevolvingIn May 2018, we entered into a Fourth Amended and Restated Credit Facility. Agreement, which provides for a maximum credit amount of $2.5 billion, subject to certain limitations. The revolving credit facility is available for working capital requirements, capital investments, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility matures in May 2020 and provides for a maximum of $1.0 billion in allowable borrowing capacity, subject to the borrowing base and certain limitations under our senior notes.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 revolving credit facility is secured by a pledgeSubstantially all of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all ofhave been mortgaged or pledged as security for our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility.


In May 2017, we entered into a Fifth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, amended the revolving credit facility to reflect an increase in the borrowing base from $700 million to $950 million. In addition, the Fifth Amendment made changes to certain of the financial and non-financial covenants in the existing agreement, as well as other administrative changes.

In October 2017, we entered into a Sixth Amendment to the Third Amended and Restated Credit Agreement. The amendment amends the revolving credit facility to allow the borrowing base to increase above the maximum allowable borrowing capacity of $1.0 billion. We have elected to increase the fall 2017 borrowing base to $1.1 billion and maintain a $700 million commitment level as of the date of this report. As of September 30, 2017, available funds2021, we had a borrowing base of $1.8 billion, an elected commitment of $1.6 billion and availability under our revolving credit facility were $700of $1.6 billion, which was net of $18.7 million based on our elected commitment level.of letters of credit outstanding.


As of September 30, 2017 and December 31, 2016, debt issuance costs related to our revolving credit facility were $6.8 million and $8.8 million, respectively, and are included in other assets on the condensed consolidated balance sheets. We had no outstanding balance on our revolving credit facility as of September 30, 2017 or December 31, 2016. 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.'sthe administrative agent'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 September 30, 2017,2021, the applicable interest margin is 1.250.75 percent for the alternate base rate option or 2.251.75 percent for the LIBOR option, and the unused commitment fee is 0.50.375 percent. No principalPrincipal payments are generally not required until the revolving credit facility expires in May 2020, or in the event that2023, unless the borrowing base falls below the outstanding balance.


The revolving credit facility contains various restrictive covenants customary for agreementsand compliance requirements, which include, among other things: (i) maintenance of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests,ratios, as defined per the revolving credit facility, include requirements to: (a) maintainincluding a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0.1.0; (ii) restrictions on the payment of cash dividends; (iii) limits on the incurrence of additional indebtedness; (iv) prohibition on the entry into commodity hedges exceeding a specified percentage of our expected production; and (v) restrictions on mergers and dispositions of assets. As of September 30, 2017,2021, we were in compliance with all thecovenants related to our revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. As defined by the revolving credit facility, our leverage ratio was 1.8 and our current ratio was 2.9 as of September 30, 2017.facility.
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)




NOTE 13 - OTHER ACCRUED EXPENSES

Other Accrued Expenses. The following table presents the componentsAs of other accrued expenses as of:

  September 30, 2017 December 31, 2016
  (in thousands)
     
Employee benefits $14,401
 $22,282
Asset retirement obligations 13,128
 9,775
Other 5,922
 6,568
Other accrued expenses $33,451
 $38,625
     

NOTE 14 - CAPITAL LEASES

We periodically enter into non-cancelable lease agreements for vehicles utilized bySeptember 30, 2021 and December 31, 2020, debt issuance costs related to our operationsrevolving credit facility were $5.6 million 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:

 September 30, 2017 December 31, 2016
  (in thousands)
Vehicles $6,301
 $2,975
Accumulated depreciation (1,435) (776)
  $4,866
 $2,199
Future minimum lease payments by year$8.1 million, respectively, and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following:
For the Twelve Months Ending September 30, Amount
  (in thousands)
2018 $2,207
2019 1,617
2020 1,758
  5,582
Less executory cost (258)
Less amount representing interest (615)
Present value of minimum lease payments $4,709
   
Short-term capital lease obligations $1,768
Long-term capital lease obligations 2,941
  $4,709

Short-term capital lease obligations are included in other accrued expensesassets on the condensed consolidated balance sheets and long-term capital lease obligations are included in other liabilities on theour condensed consolidated balance sheets.


On November 2, 2021, we entered into a Fifth Amended and Restated Credit Agreement (the “New Credit Facility”) on substantially similar terms as those in our existing revolving credit facility. The New Credit Facility, led by JPMorgan Chase Bank, provides for an aggregate maximum credit amount of $2.5 billion, has an initial borrowing base of $2.4 billion and matures in November 2026. We elected an initial commitment amount of $1.5 billion. Other significant changes in terms include: (i) a decrease in the maximum leverage ratio from 4.0:1.00 to 3.50:1.00; (ii) replacement of all provisions and related definitions regarding LIBOR with a Secured Overnight Financing Rate based benchmark rate (“SOFR”); (iii) the ability to add certain sustainability-linked key performance indicators to be agreed upon between parties that may impact the applicable margin and commitment fee rate; (iv) the addition of an investment grade period election pursuant to which we have an option to remove our borrowing base limitations and terminate the liens securing the New Credit Facility when certain debt ratings are achieved; and (v) changes to certain of our covenant baskets and event of default provisions.

Senior Notes and Convertible Notes

The following table summarizes the face values, interest rates, maturity dates, semi-annual interest payment dates, and optional redemption periods related to our outstanding senior note obligations as of September 30, 2021:

2024 Senior Notes2025 Senior Notes2026 Senior Notes
Outstanding principal amounts (in thousands)$400,000 $102,324 $750,000 
Interest rate6.125 %6.25 %5.75 %
Maturity dateSeptember 15, 2024December 1, 2025May 15, 2026
Interest payment datesMarch 15, September 15June 1, December 1May 15, November 15
Redemption periods (1)
September 15, 2022December 1, 2023May 15, 2024
_____________
(1) At any time prior to the indicated dates, we have the option to redeem all or a portion of our senior notes of the applicable series at the “make-whole” or other redemption amounts specified in the respective senior note indentures plus accrued and unpaid interest to the date of redemption. On or after the indicated dates, we may redeem all or a portion of the senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus accrued and unpaid interest to the date of redemption.

Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2024 Senior Notes, the 2025 Senior Notes and the 2026 Senior Notes (collectively, the “Senior Notes”).

The Senior Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries.

Upon the occurrence of a “change of control”, as defined in the indentures for the Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase.

The indentures governing the Senior Notes contain covenants and restricted payment provisions that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. As of September 30, 2021, we were in compliance with all covenants and all restricted payment provisions related to our Senior Notes.

Retirement of Convertible Notes. On September 15, 2021, we redeemed and retired our 2021 Convertible Notes with a cash payment for the principal amount of $200 million plus accrued and unpaid interest.
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)




Pending Retirement of Senior Notes. In October 2021, we notified the trustee of our 2024 Senior Notes of our intention to redeem approximately $200 million in aggregate principal amount of the notes at a redemption price of 101.531% of the principal plus accrued and unpaid interest. We made our payment on November 3, 2021, leaving an aggregate principal amount outstanding of $200 million. In addition, in October 2021, we notified the trustee of our 2025 Senior Notes of our intention to redeem all of the remaining outstanding principal amount of $102.3 million at a redemption price of 103.125 percent of the principal plus accrued and unpaid interest. We expect to repay our 2025 Senior Notes in December 2021.

NOTE 9 - LEASES

We have operating leases for office space and well equipment, and finance leases for vehicles. There were no significant changes in our operating and finance leases during 2021. We had short-term lease costs of $48.2 million and $158.4 million for the three and nine months ended September 30, 2021, respectively, and $18.0 million and $150.0 million for the three and nine months ended September 30, 2020, respectively. Our short-term lease costs include amounts that are capitalized as part of the cost of assets and are recorded as properties and equipment, or recognized as expense.

The following table presents the balance sheet classification of our leases as of the dates indicated:
LeasesCondensed Consolidated Balance Sheet Line ItemSeptember 30, 2021December 31, 2020
(in thousands)
Operating Leases:
Operating lease right-of-use assetsOther assets$8,677 $11,722 
Operating lease obligation - short-termOther accrued expenses6,163 6,520 
Operating lease obligation - long-termOther liabilities5,224 9,061 
Total operating lease liabilities$11,387 $15,581 
Finance Leases:
Finance lease right-of-use assetsProperties and equipment, net$3,902 $3,189 
Finance lease obligation - short-termOther accrued expenses1,369 1,466 
Finance lease obligation - long-termOther liabilities2,536 1,702 
Total finance lease liabilities$3,905 $3,168 

NOTE 1510 - ASSET RETIREMENT OBLIGATIONS


The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties:properties for the nine months ended September 30, 2021:
(in thousands)
Asset retirement obligations at beginning of period$166,570 
Obligations incurred with development activities and other4,069 
Accretion expense9,185 
Revisions in estimated cash flows(783)
Obligations discharged with asset retirements and divestitures(26,805)
Asset retirement obligations at end of period152,236 
Current portion (1)
(33,875)
Long-term portion$118,361 
_____________
 Amount
 (in thousands)
  
Balance at December 31, 2016$92,387
Obligations incurred with development activities3,296
Accretion expense4,906
Revisions in estimated cash flows155
Obligations discharged with asset retirements(8,929)
Balance at September 30, 201791,815
Less liabilities held for sale(499)
Less current portion(13,128)
Long-term portion$78,188
  
(1) The current portion of the asset retirement obligation is included in other accrued expenses on our condensed consolidated balance sheets.

Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging, abandonment and abandonmentsurface reclamation costs considering federal and state regulatory requirements in effect.effect at that time. The liability is discounted using the credit-adjusted risk-free rate estimated at the
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2021
(Unaudited)

time the liability is incurred or revised. As of September 30, 2017,To the credit-adjusted risk-free rates usedextent future revisions to discount our plugging and abandonment liabilities ranged from 6.5 percent to 8.2 percent. In periods subsequent to initial measurementthese assumptions impact the present value of the existing asset retirement obligations liability, we must recognize period-to-period changesa corresponding adjustment is made to the properties and equipment balance. Changes in the liability resulting fromdue to the passage of time revisions to eitherare recognized as an increase in the carrying amount of the original estimate of undiscounted cash flows or changes in inflation factors,liability and changes to our credit-adjusted risk-free rate as market conditions warrant. Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets.accretion expense.


NOTE 1611 - COMMITMENTS AND CONTINGENCIES


Firm Transportation and Processing Agreements. Commitments. We routinely enter into, contracts that provide firmextend or amend operating agreements in the ordinary course of business. We have long-term transportation, sales, processing and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties, and produced by our affiliated partnerships and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. Our condensed consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered.

The following table presents gross volume information related to our long-term firm transportation and processingfacility expansion agreements for pipeline capacity:
  For the Twelve Months Ending September 30,    
Area 2018 2019 2020 2021 2022 and
Through
Expiration		 Total Expiration
Date
               
Natural gas (MMcf)              
Wattenberg Field —
 16,760
 30,850
 31,025
 131,287
 209,922
 March 31, 2026
Delaware Basin 14,600
 14,600
 14,640
 3,680
 —
 47,520
 December 31, 2020
Gas Marketing 7,117
 7,117
 7,136
 7,117
 6,227
 34,714
 August 31, 2022
Utica Shale 2,738
 2,738
 2,745
 2,738
 5,016
 15,975
 July 22, 2023
Total 24,455
 41,215
 55,371
 44,560
 142,530
 308,131
  
               
Crude oil (MBbls)              
Wattenberg Field 2,413
 2,413
 1,812
 —
 —
 6,638
 June 30, 2020
               
Dollar commitment (in thousands) $18,410
 $35,170
 $44,949
 $33,776
 $129,546
 $261,851
  
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2017
(unaudited)


In anticipation of our future drilling activities in the Wattenberg Field, wecapacity and water delivery and disposal commitments. There were no significant commitments entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider is expected to construct two new 200 MMcfd cryogenic plants. We will be bound to the volume requirements in these agreements on the first day of the calendar month after the actual in-service date of the plants, which in the above table is scheduled to be in the fourth quarter of 2018 for the first plant and April 2019 for the second plant. We are currently working with this midstream provider to identify opportunities to accelerate the completion of the first of these processing facilities. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016, to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. Any shortfall of these volume commitments may be offset by additional third party producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. We currently expect that our future development plans will support the utilization of the incremental commitments.
In April 2017, we entered into a transportation service agreement for delivery of 40,000 dekatherms per day of our Delaware Basin natural gas production to the Waha market hub in West Texas. 

For each ofduring the three and nine months ended September 30, 2017,2021. For details of our commitments, for long-term transportation volumes, netrefer to our interest, for Wattenberg Field crude oil, Delaware Basin natural gas,Note 12 - Commitments and Utica Shale natural gas were $2.6 millionContingencies in Item 8. Financial Statements and $7.4 million, respectively, and were recorded in transportation, gathering, and processing expensesSupplementary Data included in our condensed consolidated statements of operations. For each ofForm 10-K for the three and nine monthsyear ended September 30, 2016, commitments for long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $2.6 million and $7.2 million, respectively.December 31, 2020.


Litigation and Legal Items.The Company isWe are involved in various legal proceedings. The Company reviewsWe review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in theour best interests of the Company. Management hasinterests. We have provided the necessary estimated accruals in the accompanying condensed consolidated balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. However, the liability ultimately incurred with respect to a matter may exceed the related accrual. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.


Environmental.Due to the nature of the naturaloil and gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of September 30, 20172021 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. However, the liability ultimately incurred with respect to a matter may exceed the related accrual. Accrued environmental liabilities are recorded in other accrued expenses on theour condensed consolidated balance sheets.

Clean Air Act Tentative AgreementFollowing a self-audit of final reclamation activities associated with site retirements, we formally disclosed identified deficiencies to the Colorado Oil and Related Consent Decree.Gas Conservation Commission (“COGCC”) in December 2019. In August 2015, we received2020, the COGCC issued a Clean Air Act Section 114 Information Request (the "Information Request"Notice of Alleged Violation (“NOAV”) fromciting a failure to comply with reclamation requirements at multiple locations. To resolve the U.S. Environmental Protection Agency ("EPA"alleged violations in July of 2021, the COGCC and PDC jointly agreed to an Administrative Order by Consent (“AOC”). The Information Request sought, among other things, information which assessed penalties in the amount of approximately $500,000, with approximately $350,000 suspended pending PDC meeting certain conditions of the AOC. We are implementing programs to meet the requirements of the AOC and correct any identified deficiencies.

On August 30, 2021, the COGCC issued us a NOAV related to the design, operation, and maintenancetiming of wellhead pressure test reporting for certain wells in the Wattenberg Field. Pursuant to the NOAV, we will perform a comprehensive audit of our Wattenberg Field production facilitieswellhead pressure testing and reporting processes to mitigate against the possibility of the alleged violations occurring in the Denver-Julesburg Basinfuture. We do not anticipate a material effect on our financial condition or results of Colorado ("DJ Basin"). The Information Request focused on historical operationoperations. However, the potential penalties may exceed $300,000.

Commencing in early 2020, we conducted a comprehensive air quality compliance audit over the facilities acquired in the SRC Acquisition. Through the self-audit process, we identified certain deficiencies and design information for 46 of our production facilities and requested sampling and analyses at the identified 46 facilities. We respondeddisclosed them to the Information Request with the requested data in January 2016.
In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. 25-7-115(2) from the Colorado Department of Public Health and Environment'sEnvironment (“CDPHE”) and the U.S. Environmental Protection Agency (“EPA”) in July 2021.We do not believe potential penalties and other expenditures associated with the deficiencies identified will have a material effect on our financial condition or results of operations, but such penalties may exceed $300,000.

Clean Air Quality Control Commission's Air Pollution Control Division allegingAct Agreement and Related Consent Decree. We continue to implement the requirements of a consent decree entered into with the CDPHE in 2017, as well as a revised compliance order on consent, the latter of which was modified by the CDPHE after the SRC Acquisition was completed. Over the course of this execution, we have identified certain immaterial deficiencies in our implementation of the programs. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that we failed to design, operate,the penalties and maintain certain condensate collection, storage, processing, and handlingexpenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $300,000. 
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)




operations to minimize leakageFurther, we could be the subject of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law.

For more than a year, we held a series of meetings with the EPA, Department of Justice (“DOJ”) and CDPHE on the above matters. On June 26, 2017, the DOJ on behalf of the EPA and the State of Colorado filed a complaint against us based on the above matters. We continued to conduct meetings with these agencies in working toward a resolution of the matters. On September 28, 2017, the parties jointly filed for an extension of time for PDC to reply to the complaint. The extension was requested because the parties reached an agreement to resolve the case subject to final approvalother enforcement actions by the appropriate persons within the federal government and state government, as well as outcome of the period of public comment on the proposed decree.

A consent decree was signed by all parties on October 31, 2017 and is subject to a 30-day comment period in which it will be publicly publishedregulatory authorities in the Federal Register. The consent decree provides that we will implement changesfuture relating to our design, operation, and maintenance of most of our field-wide storage tank systems to enhance our emission management in the DJ Basin.  Agreed upon and planned efforts include, but are not limited to, vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. We voluntarily included in the consent decree approximately 40 additional facilities associated with our pending acquisition of additional assets in the basin.  The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1 million in supplemental environmental projects); (ii) injunctive relief with an estimated cost of approximately $18 million, primarily representing capital enhancements to our operations; and (iii) mitigation with an estimated cost of $1.7 million.  Certain expenditures for the injunctive relief are believed to have been incurred in 2016 and 2017, with the remainder expected to be incurred over the next few years. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. Although we believe the consent decree will be approved by the court following the comment period, this cannot be guaranteed.  past, present, or future operations. 


NOTE 1712 - COMMON STOCK


SaleStock-Based Compensation Plans

2018 Equity Incentive Plan. In May 2020, our stockholders approved an amendment to increase the number of Equity Securities

During December 2016, we issued 9.4 million shares of our common stock as partial considerationreserved for 100 percentissuance pursuant to our long-term equity compensation plan for employees and non-employee directors (the “2018 Plan”) from 1,800,000 to 7,050,000 shares. As of September 30, 2021, there were 4,175,129 shares available for grant under the 2018 Plan.
2010 Long-Term Equity Compensation Plan. Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was approved by stockholders in 2013 (the “2010 Plan”), remains outstanding and we may continue to use the 2010 Plan to grant awards. No awards may be granted under the 2010 Plan on or after June 5, 2023. As of September 30, 2021, there were 313,477 shares available for grant under the 2010 Plan. 

2015 SRC Equity Incentive Plan. SRC PSUs were granted in connection with the closing of the common stockSRC Acquisition. For the nine months ended and as of Arris Petroleum and for the acquisition of certain Delaware Basin properties. PursuantSeptember 30, 2021, there were no changes to the terms of previously disclosed lock-up agreements, the resale of these2015 SRC Equity Incentive Plan and there were no shares was restricted. The lock-up period ended on June 4, 2017. We have registered the 9.4 million shares of our common stockavailable for resale under the Securities Act of 1933.grant.

Stock-Based Compensation Plans


The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented:


Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
(in thousands)
General and administrative expense$5,479 $5,171 $16,420 $16,632 
Lease operating expense300 234 874 809 
Total stock-based compensation expense$5,779 $5,405 $17,294 $17,441 
  Three Months Ended September 30, Nine Months Ended September 30,
  2017 2016 2017 2016
  (in thousands)
         
Stock-based compensation expense $4,761
 $4,079
 $14,587
 $15,205
Income tax benefit (1,781) (1,552) (5,457) (5,786)
Net stock-based compensation expense $2,980
 $2,527
 $9,130
 $9,419
         

Restricted Stock Units
Stock Appreciation Rights


The following table presents the changes in non-vested time-based RSUs to all employees, including executive officers, for the nine months ended September 30, 2021:
SharesWeighted-Average Grant Date Fair Value per Share
Non-vested at beginning of period1,150,970 $20.14 
Granted647,453 33.48 
Vested(531,759)25.04 
Forfeited(82,693)22.36 
Non-vested at end of period1,183,971 25.08 

The weighted-average grant date fair value of restricted stock appreciation right ("SARs") vest ratablyunits was $33.48and $12.00 for the nine months ended September 30, 2021 and 2020, respectively. Total compensation cost related to non-vested time-based awards and not yet recognized on our condensed consolidated statements of operations as of September 30, 2021 was $21.6 million. This cost is expected to be recognized over a three-yearweighted-average period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance.1.83 years.


20
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



Performance Stock Units

The Compensation Committee awarded a total of our Board of Directors awarded SARs207,655 market-based PSUs to our executive officers during the nine months ended September 30, 2017 and 2016. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:

 Nine Months Ended September 30,
 2017 2016
    
Expected term of award (in years)6
 6
Risk-free interest rate2.0% 1.8%
Expected volatility53.3% 54.5%
Weighted-average grant date fair value per share$38.58
 $26.96

The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future.
The following table presents the changes in our SARs for the nine months ended September 30, 2017:

 Number of
SARs		 Weighted-Average
Exercise
Price		 Average Remaining Contractual
Term (in years)		 
Aggregate Intrinsic
Value (in thousands)
Outstanding at December 31, 2016244,078
 $41.36
 6.9
 $7,620
Awarded54,142
 74.57
 —
 —
Outstanding at September 30, 2017298,220
 47.39
 6.7
 2,043
Exercisable at September 30, 2017186,248
 39.38
 5.6
 1,867

Total compensation cost related to non-vested SARs granted and not yet recognized in our condensed consolidated statement of operations as of September 30, 2017 was $2.3 million. The cost is expected to be recognized over a weighted-average period of1.9 years.
Restricted Stock Awards

Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three years. The time-based shares generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed.

The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the nine months ended September 30, 2017:
 Shares Weighted-Average
Grant Date
Fair Value per Share
    
Non-vested at December 31, 2016479,642
 $56.09
Granted260,019
 66.00
Vested(206,242) 56.44
Forfeited(7,990) 64.32
Non-vested at September 30, 2017525,429
 60.73
    

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2017
(unaudited)


The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:
 
As of/Nine Months Ended September 30,

 2017 2016
 (in thousands, except per share data)
    
Total intrinsic value of time-based awards vested$13,266
 $14,675
Total intrinsic value of time-based awards non-vested25,762
 35,079
Market price per common share as of September 30,49.03
 67.06
Weighted-average grant date fair value per share66.00
 57.12

Total compensation cost related to non-vested time-based awards and not yet recognized in our condensed consolidated statements of operations as of September 30, 2017 was $22.0 million. This cost is expected to be recognized over a weighted-average period of 1.9 years.

Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.
The Compensation Committee of our Board of Directors awarded a total of 28,069 market-basedrestricted shares to our executive officers during the nine months ended September 30, 2017.2021. In addition to continuous employment, the vesting of these sharesPSUs is contingent on a combination of absolute stock performance and our total stockholder return ("TSR"(“TSR”), which is essentially our stock price change, including any dividends, over a three-year period ending on December 31, 2023, as compared to the TSR of a group of peer companies.companies over the same period. The shares are measured over a three-year period ending on December 31, 2019, and canPSUs will result in a payout between 0 percentzero and 200250 percent of the total sharestarget PSUs awarded.

The weighted-average grant dategrant-date fair value per market-based share for these awards was computedestimated using thea Monte Carlo pricingvaluation model. The Monte Carlo valuation model using the following assumptions:
 Nine Months Ended September 30,
 2017 2016
    
Expected term of award (in years)3
 3
Risk-free interest rate1.4% 1.2%
Expected volatility51.4% 52.3%
Weighted-average grant date fair value per share$94.02
 $72.54

is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our common stock historical volatility.

The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the periods presented:
Nine Months Ended September 30,
20212020
Expected term of award (in years)33
Risk-free interest rate0.2%1.4%
Expected volatility84.6%46.6%
Weighted-average grant date fair value per share$54.01$33.52

SRC Performance Stock Units. The terms of the SRC PSUs are substantially the same as those of the PDC PSUs, except that the SRC PSUs do not require continuous employment and the performance period associated with the awards of January 1, 2019 through December 31, 2021 predates the grant date. The fair value of the SRC PSU awards was determined on the grant date of January 13, 2020 using the Monte Carlo pricing model using the following assumptions:

Nine Months Ended September 30, 2020
Expected term of awards (in years)2
Risk-free interest rate1.6%
Expected volatility56.9%
Weighted-average grant date fair value per share$33.35

The expected term of the awards is based on the number of years from the grant date through the end of the performance period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant, extrapolated to approximate the life of the awards. The expected volatility was based on our common stock historical volatility, as well as that of our peer group.

The following table presents the change in non-vested market-based awards, including SRC PSUs, during the nine months ended September 30, 2017:2021:
SharesWeighted-Average Grant Date Fair Value per Share
Non-vested at beginning of period499,547 $38.66 
Granted207,655 54.01 
Non-vested at end of period707,202 43.17 

Total compensation cost related to non-vested market-based awards not yet recognized on our condensed consolidated statements of operations as of September 30, 2021 was $12.8 million. This cost is expected to be recognized over a weighted-average period of 1.42 years.

21
  Shares
 Weighted-Average
Grant Date
Fair Value per Share
     
Non-vested at December 31, 2016
 48,420
 $64.97
Granted
 28,069
 94.02
Non-vested at September 30, 2017
 76,489
 75.63
     


PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 20172021
(unaudited)(Unaudited)



Stock Appreciation Rights
The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:
 As of /Nine Months Ended September 30,
 2017 2016
 (in thousands, except per share data)
    
Total intrinsic value of market-based awards vested$—
 $1,174
Total intrinsic value of market-based awards non-vested3,750
 5,670
Market price per common share as of September 30,49.03
 67.06
Weighted-average grant date fair value per share94.02
 72.54

Total compensation cost related to non-vested market-based awards not yet recognized in our condensed consolidated statements of operationsAll outstanding SARs as of September 30, 2017 was $2.9 million. This2021 have vested and the related compensation cost is expected to be recognized over a weighted-average period of 1.9 years.

Treasury Share Purchases

In June 2010, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). In accordance with the 2010 Plan, as amended in June 2013, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares granted may be either authorized but unissued shares, treasury shares, or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of SARs, paid out in the form of cash. In accordance with our stock-based compensation plans, employees and directors may surrender shares of our common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that hadhas been issued pursuant to the 2010 Plan are reissued for new grants. For shares reissued for new grants under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to additional paid-in capital. As of December 31, 2016, we had 10,397 shares remaining available for reissuance pursuant to our 2010 plan. Additionally, as of December 31, 2016, we had 18,366 of shares of treasury stock related to a rabbi trust.fully recognized. During the nine months ended September 30, 2017, we acquired 80,572 shares pursuant to our stock-based compensation plans for payment2021, 17,701 SARs were exercised at a weighted-average exercise price of tax liabilities,$30.19 and 34,551 SARs expired with a weighted-average exercise price of $52.15. As of September 30, 2021, there were 158,423 SARs outstanding and exercisable which 49,446 shares were reissuedhave a weighted-average exercise price of $51.01 and 41,523 shares are available for reissuance pursuant to the 2010 Plan.an average remaining contractual term of 3.52 years. Outstanding and exercisable SARs have $0.5 million intrinsic value as of September 30, 2021.


Preferred Stock


We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges, and restrictions as shall be fixed by our Boardboard of directors from time to time. Through September 30, 2017,2021, no shares of preferred sharesstock have been issued.


Stock Repurchase Program

In April 2019, the board of directors approved the repurchase of up to $200 million of our outstanding common stock (the “Stock Repurchase Program”). Effective upon the closing of the SRC Acquisition, our board of directors approved an increase and extension to the Stock Repurchase Program from $200 million to $525 million. Repurchases under the Stock Repurchase Program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Stock Repurchase Program does not require any specific number of shares to be acquired, is subject to market conditions and can be modified or discontinued by our board of directors at any time. Pursuant to the Stock Repurchase Program, we repurchased 2.7 million and 1.3 million shares of outstanding common stock at a cost of $108.3 million and $23.8 million during the nine months ended September 30, 2021 and 2020, respectively. We suspended the program in March 2020 due to adverse market conditions but reinstated it in February 2021. Repurchases may extend until December 31, 2023. As of September 30, 2021, $238.5 million of our outstanding common stock remained available for repurchase under the currently approved program.

Dividends

During the second and third quarters of 2021, our board of directors declared and paid a quarterly cash dividend of $0.12 per share of common stock. For the nine months ended September 30, 2021, our dividends paid totaled $0.24 per share of common stock or $23.6 million. All RSUs and PSUs receive a dividend equivalent per unit, recognized as a liability included in other liabilities on our condensed consolidated balance sheets, until the recipients receive the equivalents upon vesting. Dividends declared were recorded as a reduction of additional paid-in capital as there were no retained earnings as of the date of declaration. Future dividend payments must be approved by our board of directors and will depend on our liquidity, financial requirements, and other factors considered relevant by our board.

22
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2021
(Unaudited)

NOTE 13 - INCOME TAXES

We compute our quarterly tax provision using the effective tax rate method by applying the anticipated annual effective rate to our year-to-date income or loss, except for discrete items. Income tax on discrete items is computed and recorded in the period in which the specific transaction occurs.

We consider whether a portion, or all, of the deferred tax assets (“DTAs”) will be realized based on a more likely than not standard of judgment. The ultimate realization of DTAs is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. As of December 31, 2020, we had a full valuation allowance totaling $165.6 million against our DTAs resulting from prior year cumulative financial losses, oil and gas impairments, and significant net operating losses for U.S. federal and state income tax. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. As of September 30, 2021, there was no change in our assessment of the realizability of our DTAs. Future events or new evidence which may lead us to conclude that it is more likely than not that our net DTAs will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions.

As long as we conclude that we will continue to provide for a valuation allowance against our net DTA, we will likely not have any income tax expense or benefit other than for state income taxes. The effective income tax rates for the three and nine months ended September 30, 2021 were 0.1 percent and 0.2 percent provision on income, respectively, and 0.6 percent provision on loss and 0.5 percent benefit on loss for the three and nine months ended September 30, 2020, respectively.

As of September 30, 2021, there is 0 liability for unrecognized income tax benefits. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. The IRS has accepted our 2019 federal income tax return with no tax adjustments. We continue to voluntarily participate in the IRS CAP program for the review of our 2020 and 2021 tax years. Participation in the IRS CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings.

NOTE 1814 - EARNINGS PER SHARE


Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options,equity-based employee awards, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2017
(unaudited)



The following table presents a reconciliation of theour weighted-average basic and diluted shares outstanding:outstanding for the periods presented:

Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
(in thousands)
Weighted-average common shares outstanding - basic98,183 99,617 99,018 97,762 
Dilutive effect of:
RSUs and PSUs1,777 — 1,505 — 
Other equity-based awards6 — 11 — 
Weighted-average common shares and equivalents outstanding - diluted99,966 99,617 100,534 97,762 

 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in thousands)
        
Weighted-average common shares outstanding - basic65,865
 48,839
 65,825
 45,741
Weighted-average common shares and equivalents outstanding - diluted65,865
 48,839
 65,825
 45,741

We reported a net loss for the three and nine months endedSeptember 30, 2017 and 2016.2020. As a result, our basic and diluted weighted-average common shares outstanding were the same for each periodthose periods because the effect of the common share equivalents was anti-dilutive.


23
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2021
(Unaudited)

The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect:effect for the periods presented:
Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
(in thousands)
RSUs and PSUs6 1,831 37 1,715 
Other equity-based awards97 223 131 231 
Total anti-dilutive common share equivalents103 2,054 168 1,946 
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in thousands)
        
Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:       
Restricted stock588
 660
 585
 705
Convertible notes—
 —
 —
 345
Other equity-based awards48
 97
 82
 103
Total anti-dilutive common share equivalents636
 757
 667
 1,153
        


In September 2016, we issuedWhen outstanding, the 2021 Convertible Notes which givegave the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes could bewere not included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $85.39 conversion price during thefor any periods presented. During the three and nine months ended September 30, 2017,presented as the average market price of our common stock did not exceed the conversion price; therefore, shares issuable upon conversion ofprice. Further, the 2021 Convertible Notes were not included infully retired on the diluted earnings per share calculation.maturity date, September 15, 2021.


In November 2010, we issued $115.0 million aggregate principal amount of 3.25% convertible senior notes that were due in 2016 ("2016 Convertible Notes"), which gave the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The 2016 Convertible Notes matured in May 2016. Prior to maturity, the 2016 Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method when the average market share price exceeded the $42.40 conversion price during the periods presented.

NOTE 1915 - SUBSIDIARY GUARANTORSUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION


Our subsidiary PDC Permian, Inc. guarantees our obligations under our publicly-registered Notes. The following presents the condensed consolidating financial information separately for:

Nine Months Ended September 30,
20212020
(in thousands)
Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest$41,880 $51,556 
Income taxes(1,057)(204)
Non-cash investing and financing activities:
Change in accounts payable related to capital expenditures$21,216 $(31,403)
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals(1,538)44,339 
Issuance of common stock for the acquisition of crude oil and natural gas properties, net— 1,009,015 
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$5,848 $6,714 
Operating cash flows from finance leases77 155 
Right-of-use assets obtained in exchange for lease obligations:
Operating leases$1,189 $4,217 
Finance leases2,055 703 
24
(i)PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries;
(ii)PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our Notes;
(iii)Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor, and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and
(iv)Parent and subsidiaries on a consolidated basis ("Consolidated").

The Guarantor is 100% owned by the Parent beginning in December 2016. The Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2017
(unaudited)


the occurrence of certain customary conditions. Each entity in the condensed consolidating financial information follows the same accounting policies as described in the notes to the condensed consolidated financial statements.

The following condensed consolidating financial statements have been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column.

  Condensed Consolidating Balance Sheets
  September 30, 2017
  Parent Guarantor Eliminations Consolidated
  (in thousands)
Assets        
Current assets $299,239
 $35,463
 $—
 $334,702
Properties and equipment, net 1,911,759
 1,970,941
 —
 3,882,700
Intercompany receivable 199,871
 —
 (199,871) —
Investment in subsidiaries 1,467,623
 —
 (1,467,623) —
Noncurrent assets 89,245
 640
 —
 89,885
Total Assets $3,967,737
 $2,007,044
 $(1,667,494) $4,307,287
         
Liabilities and Stockholders' Equity        
Current liabilities $310,997
 $62,791
 $—
 $373,788
Intercompany payable —
 199,871
 (199,871) —
Long-term debt 1,051,571
 —
 —
 1,051,571
Other noncurrent liabilities 178,567
 276,759
 —
 455,326
Stockholders' equity 2,426,602
 1,467,623
 (1,467,623) 2,426,602
Total Liabilities and Stockholders' Equity $3,967,737
 $2,007,044
 $(1,667,494) $4,307,287

  Condensed Consolidating Balance Sheets
  December 31, 2016
  Parent Guarantor Eliminations Consolidated
  (in thousands)
Assets        
Current assets $387,309
 $12,516
 $—
 $399,825
Properties and equipment, net 1,884,147
 2,118,847
 —
 4,002,994
Intercompany receivable 9,415
 —
 (9,415) —
Investment in subsidiaries 1,765,092
 —
 (1,765,092) —
Goodwill —
 62,041
 —
 62,041
Noncurrent assets 20,811
 171
 —
 20,982
Total Assets $4,066,774
 $2,193,575
 $(1,774,507) $4,485,842
         
Liabilities and Stockholders' Equity        
Current liabilities $235,121
 $35,457
 $—
 $270,578
Intercompany payable —
 9,415
 (9,415) —
Long-term debt 1,043,954
 —
 —
 1,043,954
Other noncurrent liabilities 164,945
 383,611
 —
 548,556
Stockholders' equity 2,622,754
 1,765,092
 (1,765,092) 2,622,754
Total Liabilities and Stockholders' Equity $4,066,774
 $2,193,575
 $(1,774,507) $4,485,842

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2017
(unaudited)


  Condensed Consolidating Statements of Operations
  Three Months Ended September 30, 2017
  Parent Guarantor Eliminations Consolidated
  (in thousands)
         
Operating and other revenues $150,015
 $33,220
 $—
 $183,235
Production and other operating expenses 41,891
 13,129
 —
 55,020
General and administrative 26,207
 3,092
 —
 29,299
Exploration, geologic, and geophysical expense 217
 41,691
 —
 41,908
Depreciation depletion and amortization 106,623
 18,615
 —
 125,238
Impairment of properties and equipment 1,148
 251,592
 —
 252,740
Impairment of goodwill —
 75,121
 —
 75,121
Interest (expense) income (19,168) 372
 —
 (18,796)
   Loss before income taxes (45,239) (369,648) —
 (414,887)
Income tax benefit 30,274
 92,076
 —
 122,350
Equity in loss of subsidiary (277,572) —
 277,572
 —
   Net loss $(292,537) $(277,572) $277,572
 $(292,537)

  Condensed Consolidating Statements of Operations
  Nine Months Ended September 30, 2017
  Parent Guarantor Eliminations Consolidated
  (in thousands)
         
Operating and other revenues $657,102
 $74,998
 $—
 $732,100
Production and other operating expenses 118,779
 26,049
 —
 144,828
General and administrative 76,353
 8,792
 —
 85,145
Exploration, geologic, and geophysical expense 744
 43,151
 —
 43,895
Depreciation depletion and amortization 317,088
 43,479
 —
 360,567
Impairment of properties and equipment 2,282
 280,217
 —
 282,499
Impairment of goodwill —
 75,121
 —
 75,121
Provision for uncollectible notes receivable (40,203) —
 —
 (40,203)
Interest (expense) income (57,557) 685
 —
 (56,872)
  Income (loss) before income taxes 124,502
 (401,126) —
 (276,624)
Income tax expense (benefit) (32,174) 103,657
 —
 71,483
Equity in loss of subsidiary (297,469) —
 297,469
 —
   Net loss $(205,141) $(297,469) $297,469
 $(205,141)

Net losses of the Guarantor for the three and nine months ended September 30, 2017 are primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions during the relevant periods, and the impairment of goodwill during the three months ended September 30, 2017.
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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2017
(unaudited)


  Condensed Consolidating Statements of Cash Flows
  Nine Months Ended September 30, 2017
  Parent Guarantor Eliminations Consolidated
  (in thousands)
         
Cash flows from operating activities $382,715
 $28,687
 $—
 $411,402
Cash flows from investing activities:        
Capital expenditures for development of crude oil and natural properties (315,718) (213,132) —
 (528,850)
Capital expenditures for other properties and equipment (2,488) (1,252) —
 (3,740)
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition (19,761) 5,279
 —
 (14,482)
Proceeds from sale of properties and equipment 3,322
 —
 —
 3,322
Sale of promissory note 40,203
 —
 —
 40,203
Restricted cash (9,250) —
 —
 (9,250)
Sales of short-term investments 49,890
 —
 —
 49,890
Purchases of short-term investments (49,890) —
 —
 (49,890)
Intercompany transfers (189,239) —
 189,239
 —
Net cash from investing activities (492,931) (209,105) 189,239
 (512,797)
Cash flows from financing activities:        
Purchase of treasury stock (5,325) —
 —
 (5,325)
Other (906) (45) —
 (951)
Intercompany transfers —
 189,239
 (189,239) —
Net cash from financing activities (6,231) 189,194
 (189,239) (6,276)
Net change in cash and cash equivalents (116,447) 8,776
 —
 (107,671)
Cash and cash equivalents, beginning of period 240,487
 3,613
 —
 244,100
Cash and cash equivalents, end of period $124,040
 $12,389
 $—
 $136,429

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PDC ENERGY, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The following discussion and analysis as well as other sections in this report, should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere inItem 1. Financial Statements of this report. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements.Statements.


EXECUTIVE SUMMARY


Production andSeptember 30, 2021 Financial Overview of Operations and Liquidity


Market Conditions

The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. Commodity prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment.

Crude Oil Markets

In 2020, the COVID-19 pandemic led to a significant decline in commodity prices due to the decrease in demand for crude oil, negatively impacting crude oil and natural gas producers, such as PDC. Due to the decrease in oil demand, the Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing countries significantly decreased production, resulting in a low level of global supply. To date in 2021, the effects of COVID-19 mitigation efforts, including the distribution of vaccines, have aided in the recovery of the global economy. In 2021, OPEC initiated a gradual increase in production and has committed to increase output through 2021. These increases, however, have not fully offset the production cuts previously made and the effect of the increase in demand from a recovering global economy, resulting in significant price increases. The commodity price environment may remain volatile for an extended period due to, among other things, outbreaks caused by coronavirus variants, ongoing regulatory actions aimed at redirecting fossil fuel consumption towards lower carbon usage, and the overall recovery of the economy.

Natural Gas and NGL Markets

In addition to the crude oil market drivers, natural gas and NGL prices are also affected by structural changes in supply and demand as well as deviations from seasonally normal weather. The combination of these factors in 2021 have driven natural gas and NGL prices higher than recent levels.

Financial Matters

Three months ended September 30, 2021

•Production volumes increased to 8.518.8 MMboe and 23.2 MMboe forin the three and nine months ended September 30, 2017, respectively, representing increases2021 period, an increase of 426 percent and 47 percent as compared to the three2020 period, primarily driven by our drilling and nine months ended September 30, 2016, respectively. The increases in production volumes were primarily attributable to the continued success of our horizontal Niobrara and Codell drilling programcompletion activities in the Wattenberg Field and growing production from our Delaware Basin properties.Crude oil production increased 47 percent forsince the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016, respectively. Crude oil production comprised approximately 40 percentthird quarter of total production in each of the three and nine months ended September 30, 2017. NGL production increased 33 percent and 54 percent for the three and nine months ended September 30, 2017, respectively, compared to the three and nine months ended September 30, 2016. Natural gas production increased 42 percent and 43 percent in the three and nine months ended September 30, 2017, respectively, compared to the three and nine months ended September 30, 2016.On a combined basis, total liquids production comprised 63 percent of our total production during each of the three months ended September 30, 2017 and September 30, 2016, and 62 percent and 61 percent of total production during the nine months ended September 30, 2017 and September 30, 2016, respectively. For the three months ended September 30, 2017, we maintained an average daily production rate of approximately 92,500 Boe per day, including 12,800 Boe per day from the Delaware Basin, up from approximately65,300 Boe per day for the three months ended September 30, 2016.2020.


•On a sequential quarterly basis, total production volumes for the three months ended September 30, 2017increased 8 percent to 18.8 MMboe as compared to the three months ended June 30, 2017 increased with contributions from both the Wattenberg Field and Delaware Basin. For the three months ended September 30, 2017 as compared to the three months ended June 30, 2017, total production and crude oil production each increased by six percent. Continued high line pressures17.4 MMboe in the Wattenberg Field have temporarily tempered the growth rate in the Wattenberg Field; however, we are expecting an overall modest sequential quarterly increase in production in the fourthsecond quarter of 2017.2021 due to a higher number of wells turned-in-line and non-operated well activities during the third quarter of 2021.


•Crude oil, natural gas and NGLs sales increased to $232.7$703.1 million and $636.0compared to $314.9 million in the three and nine months ended September 30, 2017, respectively, compared2020 primarily due to $141.8 million and $328.0 millionan 111 percent increase in the three and nine months ended September 30, 2016, respectively. These 64 percent and 94 percent increases in sales revenues were driven by the 42 percent and 47 percent increases in production and 16 percent and 32 percent increases inweighted average realized commodity prices.prices and a 6 percent increase in production volumes between periods.


We had positive•Incurred negative net settlements from our commodity derivative contracts of $9.6$129.6 million for the three months ended September 30, 2017 as compared to positive net settlements of $47.7$66.9 million for the three months ended September 30, 2016. We had positive net settlements of $22.2 million for the nine months ended September 30, 2017, as comparedin 2020 due to positive net settlements of $167.9 million for the nine months ended September 30, 2016. We entered into agreements for the derivative instruments that settled throughout 2016 prior toan improvement in commodity prices becoming depressed in late 2014.  Substantially all of these higher-value derivatives settled byduring the end of 2016.  Net settlements for the three and nine months ended September 30, 2017 reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices.  Based upon the forward strip pricing at September 30, 2017, we expect that settlements will continue to be substantially lower in 2017 than in 2016. See Results of Operations - Commodity Price Risk Management, Net for further details of our settlements of derivatives and changes in the fair value of unsettled derivatives.2021 period.


The combined•Combined revenue from crude oil, natural gas and NGLs sales and net settlements received onfrom our commodity derivative instruments increased 2850 percent to $242.3$573.5 million from $381.8 million in the three months ended September 30, 2017 from $189.5 million in the three months ended September 30, 2016, and increased 33 percent to $658.2 million in the nine months ended September 30, 2017 from $495.9 million in the nine months ended September 30, 2016.



2020.
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25
PDC ENERGY, INC.


During the three months ended September 30, 2017, we recorded exploratory dry hole well expense•Generated net income of $41.2$145.3 million, an unproved property impairment charge of $251.6 million, and we impaired all of the goodwill associated with the assets acquired in the Delaware Basin, which resulted in an impairment charge of $75.1 million. For more information regarding these expenses and charges see Results of Operations - Exploration, Geologic, and Geophysical Expense, Results of Operations - Impairments of Properties, and Results of Operations - Impairment of Goodwill.

In the three and nine months ended September 30, 2017, we generatedor $1.45 per diluted share, compared to a net loss of $292.5$30.8 million, and $205.1 million, respectively, or $4.44 and $3.12$0.31 per diluted share, respectively. Ourfor the comparable period in 2020. The net income recognized in 2021 compared to a net loss in 2020 was negatively impactedprimarily due to an increase in crude oil, natural gas and NGLs sales of $388.2 million partially offset by the aforementioned impairment charges and expensingan increase in commodity price risk management loss of exploratory dry hole well costs. During the same periods, our adjusted$149.6 million.

•Adjusted EBITDAX, a non-U.S. GAAP financial measure, was $166.9$432.0 million compared to $278.8 million for the comparable period in 2020, primarily due to an increase in sales of $191.7 million, net of negative net derivative settlements.

Nine months ended September 30, 2021

•Production volumes were 51.9 MMboe for the 2021 period, relatively flat compared to the 2020 period due to reduced capital expenditures in the second half of 2020 resulting from the COVID-19 related decrease in demand for oil and $497.6natural gas.

•Crude oil, natural gas and NGLs sales increased to $1.7 billioncompared to $809.2 million respectively. Beginning in 2017, we have included non-cash stock-based compensation2020, primarily due to the 110 percent increase in weighted average realized commodity prices.

•Incurred negative net settlements from our commodity derivative contracts of $215.4 millioncompared to positive net settlements of $227.5 million in 2020 due to improvement in commodity prices during 2021.

•Combined revenue from crude oil, natural gas and exploration, geologicNGLs sales and geophysicalnet settlements from our commodity derivative instruments increased 44 percent to $1.5 billion from $1.0 billion in 2020.

•Generated net income of $49.2 million, or$0.49per diluted share, compared to a net loss of $717.6 million, or$7.34per diluted share, in 2020. The net income during the period compared to net loss in the prior period was most significantly impacted by an increase in crude oil, natural gas and NGLs sales of $895.2 million, a decrease in general and administrative expense of $33.6 million realized during 2021 and an $882.3 million impairment charge recognized in our reconciliationthe first quarter of adjusted EBITDAX.  In prior periods, we reported adjusted EBITDA,2020. These positive factors were partially offset by a $707.2 million commodity price risk management loss in 2021 compared to $245.9 million in commodity price risk management gains in 2020 and an increase in production taxes of $60.2 million between periods.

•Adjusted EBITDAX, a non-U.S. GAAP financial measure, that did not include these adjustments.  All prior periods have been conformed for comparabilitywas $1,106.0 millioncompared to $705.2 million in 2020, primarily due to an increase in sales of this updated presentation. In the three and nine months ended September 30, 2016, our$452.3 million, net loss per diluted share was $0.48 and $4.16, respectively, and our adjusted EBITDAX was $133.0 million and $313.3 million, respectively. Our cash flowof negative net derivative settlements.

•Cash flows from operations was $411.4increased to $1,027.8 million and our adjustedcompared to $649.3 million in 2020. Adjusted cash flowflows from operations, a non-U.S. GAAP financial measure, was $407.5increased to $1,059.5 millioncompared to $652.8 million in the nine months ended September 30, 2017. 2020. Adjusted free cash flows, a non-U.S. GAAP financial measure, increased to $609.5 million from $238.7 million in 2020.

See Reconciliation of Non-U.S. GAAP Financial Measures, below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.

Liquidity

Available liquidity as of September 30, 2017 was $836.4 million, which was comprised of $136.4 million of cash and cash equivalents and $700 million available for borrowing under our revolving credit facility at our current commitment level. We expect decreases in our cash balance during the remainder of 2017 due to: (i) the expected closing of the pending Wattenberg Field acquisition described below, (ii) continued planned development in the core Wattenberg Field, and (iii) further capital investment in our Delaware Basin assets. In October 2017, we entered into a Sixth Amendment to the Third Amended and Restated Credit Agreement. The amendment allowed the borrowing base to be set above the $1.0 billion allowable borrowing capacity of the facility. The borrowing base redetermination for the fall of 2017 was confirmed at $1.1 billion and we elected to maintain a $700 million commitment level as of the date of this report.

We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, potential utilization of our borrowing capacity under our revolving credit facility, and if warranted, capital markets transactions from time to time.


Pending Acquisition and Acreage Exchanges

Pending Acquisition. In September 2017, we entered into a purchase and sale agreement to acquire certain assets from Bayswater and certain related parties, pursuant to which, subject to the terms and conditions of the agreement, we have agreed to acquire approximately 8,300 net acres, 30 DUCs, and an incremental 240 gross drilling locations, for approximately $210 million in cash, subject to certain pre- and post-closing adjustments. We plan to turn-in-line 18 of these DUCs at approximately year-end 2017, with the completion costs expected to be treated as an increase to the purchase price. Upon executing the purchase and sale agreement, we paid a $21 million deposit toward the purchase price into an escrow account, which is included in other assets in our September 30, 2017 condensed consolidated balance sheet. Assuming all conditions required for closing are met, the acquisition is expected to close in December 2017 and will be funded by a combination of available cash and debt.

Pending Acreage Exchanges. In September 2017, we entered into an acreage exchange transaction to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we will exchange leasehold acreage with some limited in-process development wells. Upon closing, we expect to receive approximately 11,700 net acres in exchange for approximately 12,100 net acres, with minimal cash exchanged between the parties. The difference in net acres is primarily due to variances in working and net revenue interests. The acreage exchange is anticipated to close in the fourth quarter of 2017; however, there can be no assurance that conditions to closing will be satisfied.

In June 2017, we entered into an acreage exchange transaction that also involves the consolidation of certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we will exchange leasehold acreage with some limited in-process development wells. Upon closing, we estimate that we will receive approximately 3,900 net acres in
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26
PDC ENERGY, INC.

Drilling and Completion Overview
exchange for approximately 4,100 net acres with minimal cash exchanged between the parties. The difference in net acres is primarily due to variances in working and net revenue interests. This acreage exchange is also expected to close in the fourth quarter of 2017; however, there can be no assurance that conditions to closing will be satisfied.

Operational Overview


During the nine months ended September 30, 2017,2021, we continued to execute our strategic plan to grow production while preserving our financial strengthoperated one full-time drilling rig, one spudder rig and liquidity. Our drilling efficiencyone full-time completion crew in the Wattenberg Field over the last nine months has resultedField. In addition, we operated one full-time drilling rig and one part-time completion crew, which started in shorter drill cycle times; therefore, we decreased our rig count to three rigsMarch and ended in the fourth quarter of 2017. Because of the shorter drill times, the impact of the reduced rig count on our expected turn-in-line count in the Wattenberg Field is expected to be minimal in 2017. In the Delaware Basin, during the three months ended September 30, 2017, we adjusted to operating three drilling rigs. During the third quarter of 2017, we turned in line to sales 39 wells in Wattenberg and four wellsJune, in the Delaware Basin.
The following tables summarizes our drilling Our total capital investments in crude oil and completion activitynatural gas properties for the nine months ended September 30, 2017:2021 were $450.0 million.


The following tables summarize our drilling and completion activities for the nine months ended September 30, 2021:
  Wells Operated by PDC
  Wattenberg Field Delaware Basin Total
   Gross  Net Gross Net Gross Net
In-process as of December 31, 2016 64
 52.7
 5
 4.8
 69
 57.5
Wells spud 119
 105.6
 18
 16.6
 137
 122.2
Wells turned-in-line to sales (111) (93.6) (11) (10.2) (122) (103.8)
 Exploratory dry holes —
 —
 (2) (2.0) (2) (2.0)
In-process as of September 30, 2017 72
 64.7
 10
 9.2
 82
 73.9


Operated Wells
Wattenberg FieldDelaware BasinTotal
 Gross NetGrossNetGrossNet
In-process as of December 31, 2020214 201.8 20 19.0 234 220.8 
Wells spud63 60.4 15 15.0 78 75.4 
Wells turned-in-line(113)(108.9)(18)(17.4)(131)(126.3)
In-process as of September 30, 2021164 153.3 17 16.6 181 169.9 
  Wells Operated by Others
  Wattenberg Field Delaware Basin Total
   Gross  Net Gross Net Gross Net
In-process as of December 31, 2016 18
 3.4
 —
 —
 18
 3.4
Wells spud 89
 12.2
 7
 1.0
 96
 13.2
Wells turned-in-line to sales (40) (4.5) (2) (0.4) (42) (4.9)
In-process as of September 30, 2017 67
 11.1
 5
 0.6
 72
 11.7


Our in-process wells represent wells that are in the process of being drilled and/or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our DUCsin-process wells are generally completed and turned in-line to salesturned-in-line within three totwo years of drilling.

Capital Returns

Debt Reduction. During the nine months ended September 30, 2021, we made net debt repayments of drilling. The majority$168.0 million on our revolving credit facility, resulting in no outstanding balance at the period end. In addition, on September 15, 2021, we redeemed and retired our 2021 Convertible Notes with a cash payment for the principal amount of $200 million, plus accrued and unpaid interest.

In October 2021, we notified the trustee of our 2024 Senior Notes of our intention to redeem approximately $200 million aggregate principal amount of the PDC-operated in-process wellsnotes at each period enda redemption price of 101.531 percent of the principal plus accrued and unpaid interest. We made our payment on November 3, 2021, leaving an aggregate principal amount outstanding of $200 million. Also, in October 2021, we notified the trustee of our 2025 Senior Notes of our intention to redeem all of the remaining outstanding principal amount of $102.3 million at a redemption price of 103.125 percent of the principal plus accrued and unpaid interest. We expect to repay our 2025 Senior Notes on December 1, 2021.

Stock Repurchase Program. In February 2021, we reinstated our Stock Repurchase Program. We repurchased 1.5 million and 2.7 million shares of outstanding common stock at a cost of $59.7 million and $108.3 million for the three and nine months ended September 30, 2021, respectively. As of September 30, 2021, $238.5 millionof our outstanding common stock remained available for repurchases under the program.

Dividends. In the second and third quarters of 2021, our board of directors declared quarterly cash dividends of $0.12 per share of common stock. For the nine months ended September 30, 2021, our dividends paid totaled $23.6 million.

2021 Operational and Financial Outlook

We anticipate that our production in 2021 will range between 190,000 Boe to 195,000 Boe per day, approximately 60,000 Bbls to 63,000 Bbls of which are DUCs, asexpected to be crude oil. Our planned 2021 capital investments in crude oil and natural gas properties, which we do not begin the completion process until the entire well pad is drilled. As we continueexpect to monitorbe between $550 million and $600 million, are focused on continued execution of our capital investment and due to the efficiencies gained by our operating teamdevelopment plans in the Wattenberg Field we expect that we willand the Delaware Basin.

We have an increase of approximately 25 wells in our in-process well count at December 31, 2017 relativeoperational flexibility to September 30, 2017. All appropriate costs incurred throughcontrol the end of the period have been capitalized, while the capital investment to complete the wells will be incurred in the period in which the wells are completed. We expect that the level of non-operated well activity reflected in the table above will decrease upon the anticipated closingpace of our aforementioned pending acreage exchanges.

2017 Operational Outlook

Based on our revised timing of well completions and the estimated productivity of wells associated withcapital spending. As we execute our capital investment program, we currently believe thatcontinually monitor, among other things, expected rates of return, the political environment and our 2017 production will be approximately 32 MMBoe. We expect that approximately 40 percent of our 2017 production will be crude oil and approximately 23 percent will be NGLs, for total liquids of approximately 63 percent. The anticipated percentage of production from NGLs has increased due to the success of field recovery efforts and improved yields by our third-party processors in the Wattenberg Field.

We expect our capital expenditures to be approximately $800 million in 2017, which takes into account the current increased per well costs in the Delaware Basin and the anticipated increase in the expected number of wells to be spud in the Wattenberg Field during the year compared to our original 2017 budget. As previously disclosed, we added a third and fourth rig in the first quarter of 2017 in the Delaware Basin, which was sooner than initially contemplated in our budget,remaining inventory in order to protect certain leasehold positionsbest meet our short- and long-term corporate strategy. We may revise our 2021 capital investment program for the remainder of the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, requirements to create greater future operational flexibility. Finally, some additionalhold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain
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continuous activity on leaseholds, and acquisition and divestiture opportunities. In the second quarter of 2021, we started experiencing minor increases in capital and operating costs which were partially offset by our completion cost efficiencies. We anticipate further modest increases in costs if oil and gas pricing remains near or exceeds current levels.

Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which is further delineated between the Kersey, Prairie, Plains, and Summit development areas. Our 2021 capital investment has been included in our forecastprogram for the closed and anticipated Wattenberg Field acreage trades that would, if completed, increaserepresents approximately 75 percent of our working interestexpected total capital investments in certain wells.

Wattenberg Field. The 2017 capital investment forecastcrude oil and natural gas properties, and approximately 90 percent is estimated at approximately $450 millionexpected to be invested in operated drilling and completion activity. We plan to drill standard-reach lateral (“SRL”), mid-reach lateral (“MRL”) and extended-reach lateral (“XRL”) wells in the Wattenberg Field. Our plan contemplates running three rigs in the field in the fourth quarter of 2017. Approximately $445 million is expected to be allocated to development activities, comprised of approximately $425 million for our operated drilling program and approximately $20 million for wells drilled and operated by others. The remainder is expected to be used for miscellaneous well equipment and capital projects. Wells in the Wattenberg Field typically have productive horizons at a depth of approximately 6,500 to 7,500 feet below the surface. Our revised investment forecast anticipatesIn 2021, we anticipate spudding approximately 15575 to 80 operated wells and turning-in-line approximately 133 horizontal150 to 160 operated wells with lateral lengthswells. For the remainder of 4,000 to 10,000 feet. We do not2021, we expect to increase our 2017 capital investment forecast in connectionoperate with the acquisition agreement we entered intoone full-time horizontal drilling rig crew and one full-time completion crew along with Bayswater and certain related parties, as the acquisition is expected to close late in December. There are expected to be costs in addition to the $210 million purchase price as a result of continued capital activity on the DUCs being acquired in the transaction, which will be accounted for as additional purchase price.

Delaware Basin. We are currently operating a three-rig drilling program in the Delaware Basin. Total capital investment in the Delaware Basin for the year is estimated to be approximately $345 million, of which approximately $285 million is expected to be used to spud 24 and turn-in-line an estimated 20 wells. Expected per well drilling costs in the Delaware Basin have increased by approximately 10 to 15 percent during the third quarter of 2017 as compared to the second quarter of 2017, primarily due to higher costs of services and supplies and longer than anticipated drill cycle times.  To enhance our understandingpart-time spudder rig. The remainder of the geology in the Delaware Basin, we initiated various engineering studies on a large portion of our Delaware Basin wells, including expanded depth pilot holes and logging/seismic services. These studies are providing important information to our operating team; however, they have come with additional unexpected costs. Additionally, mechanical issues have resulted in cost overruns for certain wells we have drilled in the area. Of the 20 planned turn-in-lines during 2017, nine are expected to have extended laterals of approximately 10,000 horizontal feet with an estimated 70 to 75 completion stages per well. Similarly spaced completion stages are anticipated for the remaining 11 turn-in-lines. Wells in the Delaware Basin typically have productive horizons at a depth of approximately 9,000 to 11,000 feet below the surface. We plan to invest approximately $15 million for leasing, seismic, and technical studies with an additional $35 million for midstream-related projects including gas connections and surface location infrastructure. The remaining $10 million of the Delaware BasinWattenberg Field capital investment program is expected to be used for land, capital workovers, facilities projects, and non-operated drilling.

Delaware Basin. Total capital projects.investments in crude oil and natural gas properties in the Delaware Basin for 2021 are expected to be approximately 25 percent of our total capital investments, and approximately 85 percent is expected to be invested in operated drilling and completion activity. In June 2021, we concluded our operated completion program for the year by completing and turning-in-line 18 wells.We will continue to operate with one drilling rig for the remainder of 2021 and we anticipate spudding approximately 17 to 20 operated wells for the year. The majority of the remaining wells we plan to drill in 2021 in the Delaware Basin are MRL and XRL wells.



We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2021, we expect 2021 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. We expect that any excess cash flows from operations will be used to reduce our indebtedness, return capital to our shareholders, and for general corporate purposes.


Regulatory and Political Updates

In Colorado, certain interest groups opposed to oil and natural gas development have proposed ballot initiatives that could hinder or eliminate the ability to develop resources in the state. In 2019, the Colorado legislature passed Senate Bill 19-181 (“SB 19-181”) to address concerns underlying the ballot initiatives.

As part of SB 19-181, a series of rulemaking hearings were conducted, which focused on issues such as permitting requirements, setbacks and siting requirements, resulting in the adoption of new regulatory requirements. Rulemakings focused on financial assurance and permit fees have not been completed. The financial assurance rulemaking could result in increased bonding requirements, though the final language and impact will not be known until early 2022.

A key component of SB 19-181 was the change in the COGCC mission from “fostering” the industry to “regulating” the industry. As a result, changes were made to the permitting process in Colorado. As of January 2021, permits are now designed as Oil and Gas Development Plans (“OGDP”), which streamlines single pad locations or proximate multi-pad locations into a single permitting package. Operators also have an option to pursue a Comprehensive Area Plan (“CAP”). A CAP is designed to represent a landscape-level look at oil and gas development in a larger area over a longer period of time, and to include multiple OGDPs within its boundaries. As both CAPs and OGDPs are new processes and the COGCC staff is working to develop the appropriate requirements and adjusting to their new operating plan, the time needed to obtain a permit has been prolonged. COGCC rules provide that the permitting process could range between six to twelve months or more from submission to approval.

We cannot predict whether future ballot initiatives or other legislation or regulation will be proposed that would limit the areas of the state in which drilling is permitted to occur or impose other requirements or restrictions.

Wattenberg Permits Update. PDC was granted unanimous approval for an 8-well OGDP located in rural Weld County in early October 2021, our first approval under the new permitting process resulting from a company-wide collaborative effort. As part of the permit process, we successfully obtained consent from all nearby residents and landowners, which was an option designed by the COGCC for locations with residential building units within 2,000 feet. Additionally, in late September, we submitted our application for an OGDP covering an approximate 70-well, multi-pad development plan and we are making continuous progress towards the targeted year-end submittal of a CAP that will cover an estimated 450 future drilling locations, each located in rural Weld County. This CAP would represent our planned turn-in-line activity into 2027.

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Environmental, Social and Governance

We recognize the importance of reducing our environmental footprint and voluntarily participating in emission reduction initiatives. These initiatives, which include plugging and reclamation of legacy vertical wells, retrofits of air pneumatics on older facilities, electrification of our facilities, technological innovations and other activities, will require capital and operational investments which are built into our annual and multi-year budgeting process. We anticipate reclaiming approximately 300 legacy vertical wells over the next 12 months, which will reduce our overall emissions intensity. We have recognized approximately $30 million as a current liability associated with the reclamation of these wells within other accrued expenses on our condensed consolidated balance sheet. We do not anticipate these projects to have a material impact on our operations.

In September 2021, we incorporated environmental, social and governance (“ESG”) as part of the responsibility of the Nominating and Governance Committee of our board of directors, formalizing board oversight of our ESG program as the Environmental, Social, Governance and Nominating Committee. Additionally in September 2021, we issued a Sustainability Report addressing a variety of ESG and sustainability matters. The Sustainability Report is available on our website at www.pdce.com and is not incorporated by reference in this report.

The SEC and other regulatory bodies are proposing a number of climate change-focused and broader ESG reporting requirements. If adopted, we will modify our disclosures accordingly.


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Results of Operations


Summary of Operating Results


The following table presents selected information regarding our operating results:
Three Months Ended September 30,Nine Months Ended September 30,
20212020Percent Change20212020Percent Change
(dollars in millions, except per unit data)
Production:
Crude oil (MBbls)6,109 6,029 1 %16,357 18,133 (10)%
Natural gas (MMcf)45,202 41,747 8 %128,714 123,802 4 %
NGLs (MBbls)5,122 4,714 9 %14,119 13,028 8 %
Crude oil equivalent (MBoe)18,764 17,701 6 %51,928 51,794 — %
Average Boe per day (Boe)203,957 192,402 6 %190,212 189,029 1 %
Crude Oil, Natural Gas and NGLs Sales:
Crude oil$422.6 $226.0 87 %$1,046.9 $591.0 77 %
Natural gas135.5 41.9 223 %326.9 112.5 191 %
NGLs145.0 47.0 209 %330.6 105.7 213 %
Total crude oil, natural gas and NGLs sales$703.1 $314.9 123 %$1,704.4 $809.2 111 %
Net Settlements on Commodity Derivatives
Crude oil$(98.0)$69.7 (241)%$(166.4)$231.7 (172)%
Natural gas(31.6)(2.8)*(49.0)(4.2)*
Total net settlements on derivatives$(129.6)$66.9 (294)%$(215.4)$227.5 (195)%
Average Sales Price (excluding net settlements on derivatives):
Crude oil (per Bbl)$69.17 $37.49 85 %$64.00 $32.59 96 %
Natural gas (per Mcf)3.00 1.00 200 %2.54 0.91 179 %
NGLs (per Bbl)28.33 9.97 184 %23.41 8.12 188 %
Crude oil equivalent (per Boe)37.47 17.79 111 %32.82 15.62 110 %
Average Costs and Expenses (per Boe):
Lease operating expense$2.43 $2.11 15 %$2.50 $2.37 5 %
Production taxes2.38 0.83 187 %1.95 0.79 147 %
Transportation, gathering and processing expense1.42 1.38 3 %1.43 1.06 35 %
General and administrative expense1.64 1.84 (11)%1.86 2.51 (26)%
Depreciation, depletion and amortization9.04 8.16 11 %9.22 9.08 2 %
Lease Operating Expense by Operating Region (per Boe)
Wattenberg Field$2.15 $1.89 14 %$2.20 $2.17 1 %
Delaware Basin4.09 3.21 27 %4.50 3.42 32 %
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 Percentage Change 2017 2016 Percentage Change
 (dollars in millions, except per unit data)
Production           
Crude oil (MBbls)3,439
 2,340
 47.0 % 9,184
 6,241
 47.2 %
Natural gas (MMcf)19,070
 13,417
 42.1 % 52,437
 36,768
 42.6 %
NGLs (MBbls)1,892
 1,428
 32.5 % 5,249
 3,402
 54.3 %
Crude oil equivalent (MBoe)8,509
 6,004
 41.7 % 23,172
 15,771
 46.9 %
Average Boe per day (Boe)92,491
 65,263
 41.7 % 84,880
 57,558
 47.5 %
Crude Oil, Natural Gas and NGLs Sales           
Crude oil$157.0
 $98.5
 59.4 % $428.8
 $233.0
 84.0 %
Natural gas41.5
 27.4
 51.5 % 116.7
 59.6
 95.8 %
NGLs34.2
 15.9
 115.1 % 90.5
 35.4
 155.6 %
Total crude oil, natural gas, and NGLs sales$232.7
 $141.8
 64.1 % $636.0
 $328.0
 93.9 %
            
Net Settlements on Commodity Derivatives           
Crude oil$5.4
 $39.5
 (86.3)% $7.4
 $131.6
 (94.4)%
Natural gas6.3
 8.2
 (23.2)% 16.8
 36.3
 (53.7)%
NGLs (propane portion)(2.1) —
 *
 (2.0) —
 *
Total net settlements on derivatives$9.6
 $47.7
 (79.9)% $22.2
 $167.9
 (86.8)%
            
Average Sales Price (excluding net settlements on derivatives)        
Crude oil (per Bbl)$45.66
 $42.11
 8.4 % $46.69
 $37.33
 25.1 %
Natural gas (per Mcf)2.17
 2.04
 6.4 % 2.23
 1.62
 37.7 %
NGLs (per Bbl)18.11
 11.12
 62.9 % 17.24
 10.41
 65.6 %
Crude oil equivalent (per Boe)27.35
 23.62
 15.8 % 27.45
 20.80
 32.0 %
            
Average Costs and Expenses (per Boe)           
Lease operating expenses$2.98
 $2.33
 27.9 % $2.81
 $2.73
 2.9 %
Production taxes1.82
 1.59
 14.5 % 1.85
 1.25
 48.0 %
Transportation, gathering and processing expenses1.15
 0.84
 36.9 % 0.96
 0.86
 11.6 %
General and administrative expense3.44
 5.41
 (36.4)% 3.67
 5.00
 (26.6)%
Depreciation, depletion and amortization14.72
 18.81
 (21.7)% 15.56
 20.12
 (22.7)%
            
Lease Operating Expenses by Operating Region (per Boe)          
Wattenberg Field$2.49
 $2.39
 4.2 % $2.45
 $2.77
 (11.6)%
Delaware Basin6.07
 —
 *
 5.76
 —
 *
Utica Shale1.91
 1.27
 50.4 % 1.60
 1.87
 (14.4)%
____________

*Percentage* Percent change is not meaningful.
Amounts may not recalculate due to rounding.meaningful.





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Crude Oil, Natural Gas and NGLs Sales


ForCrude oil, natural gas and NGLs sales for the three and nine months ended September 30, 2017, crude oil, natural gas, and NGLs sales revenue2021 increased compared to the three and nine months ended September 30, 20162020 due to the following (in millions):following:


Three Months Ended September 30, 2021Nine Months Ended September 30, 2021
(in millions)
Change in:
Production$10.5 $(44.5)
Average crude oil price193.6 513.8 
Average natural gas price90.1 210.0 
Average NGLs price94.0 215.9 
Total change in crude oil, natural gas and NGLs sales revenue$388.2 $895.2 
 September 30, 2017
 Three Months Ended Nine Months Ended
 (in millions)
Increase in production$63.0
 $154.5
Increase in average crude oil price12.2
 86.0
Increase in average natural gas price2.5
 31.7
Increase in average NGLs price13.2
 35.8
Total increase in crude oil, natural gas and NGLs sales revenue$90.9
 $308.0

The negative impact in sales relating to the change in production volumes during the nine months ended September 30, 2021 compared to the same period in 2020 was significantly impacted by a 10 percent decrease in crude oil production between periods.

Crude Oil, Natural Gas and NGLs Production


The following tables presenttable presents crude oil, natural gas and NGLs production. Our acquisitionsproduction for the periods presented:

Three Months Ended September 30,Nine Months Ended September 30,
Production by Operating Region20212020Percent Change20212020Percent Change
Crude oil (MBbls)
Wattenberg Field4,925 4,888 1 %13,595 14,984 (9)%
Delaware Basin1,184 1,141 4 %2,762 3,149 (12)%
Total6,109 6,029 1 %16,357 18,133 (10)%
 Natural gas (MMcf)
Wattenberg Field39,538 35,450 12 %113,280 105,286 8 %
Delaware Basin5,664 6,297 (10)%15,434 18,516 (17)%
Total45,202 41,747 8 %128,714 123,802 4 %
NGLs (MBbls)
Wattenberg Field4,532 4,006 13 %12,685 11,037 15 %
Delaware Basin590 708 (17)%1,434 1,991 (28)%
Total5,122 4,714 9 %14,119 13,028 8 %
Crude oil equivalent (MBoe)
Wattenberg Field16,047 14,803 8 %45,160 43,569 4 %
Delaware Basin2,717 2,898 (6)%6,768 8,225 (18)%
Total18,764 17,701 6 %51,928 51,794 — %
Average crude oil equivalent per day (Boe)
Wattenberg Field174,424 160,902 8 %165,421 159,011 4 %
Delaware Basin29,533 31,500 (6)%24,791 30,018 (17)%
Total203,957 192,402 6 %190,212 189,029 1 %


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PDC ENERGY, INC.
Net production volumes for oil, natural gas and NGLs increased6 percent during the three months ended September 30, 2021 compared to the same period in 2020. The increase in production volume between periods was primarily due to a greater number of assetswells turned-in-line since the third quarter of 2020. This increase was partially offset by normal decline in production from our existing wells and lower performance of wells turned-in-line in the Delaware Basin closedduring 2021.

Net production volumes for oil, natural gas and NGLs were relatively flat during the nine months ended September 30, 2021 compared to the same period in December 2016; therefore, there is no comparative data2020 due to reduced capital expenditures in the second half of 2020 resulting from the COVID-19 related decrease in demand for oil and natural gas.

The following table presents our crude oil, natural gas and NGLs production ratio by operating region for the periods presented:

Three Months Ended September 30, 2021
Crude OilNatural GasNGLsTotal
Wattenberg Field31%41%28%100%
Delaware Basin43%35%22%100%
Three Months Ended September 30, 2020
Crude OilNatural GasNGLsTotal
Wattenberg Field33%40%27%100%
Delaware Basin40%36%24%100%
Nine Months Ended September 30, 2021
Crude OilNatural GasNGLsTotal
Wattenberg Field30%42%28%100%
Delaware Basin41%38%21%100%
Nine Months Ended September 30, 2020
Crude OilNatural GasNGLsTotal
Wattenberg Field34%41%25%100%
Delaware Basin38%38%24%100%

The change in production mix in the Wattenberg Field during the three and nine months ended September 30, 2016:2021 compared to the same periods in 2020was driven by 2021 developmental plans being focused on areas that have a higher gas/oil ratio and the variability of our quarterly capital spend.

  Three Months Ended September 30, Nine Months Ended September 30,
Production by Operating Region 2017 2016 Percentage Change 2017 2016 Percentage Change
Crude oil (MBbls)            
Wattenberg Field 2,943
 2,216
 32.8 % 7,883
 5,929
 33.0 %
Delaware Basin 436
 —
 *
 1,075
 —
 *
Utica Shale 60
 124
 (51.4)% 226
 312
 (27.7)%
Total 3,439
 2,340
 47.0 % 9,184
 6,241
 47.2 %
 Natural gas (MMcf)            
Wattenberg Field 15,788
 12,700
 24.3 % 44,694
 34,968
 27.8 %
Delaware Basin 2,781
 —
 *
 6,052
 —
 *
Utica Shale 501
 717
 (30.2)% 1,691
 1,800
 (6.0)%
Total 19,070
 13,417
 42.1 % 52,437
 36,768
 42.6 %
NGLs (MBbls)            
Wattenberg Field 1,564
 1,353
 15.6 % 4,473
 3,240
 38.0 %
Delaware Basin 282
 —
 *
 625
 —
 *
Utica Shale 46
 75
 (38.7)% 151
 162
 (7.3)%
Total 1,892
 1,428
 32.5 % 5,249
 3,402
 54.3 %
Crude oil equivalent (MBoe)            
Wattenberg Field 7,138
 5,686
 25.5 % 19,805
 14,997
 32.1 %
Delaware Basin 1,182
 —
 *
 2,709
 —
 *
Utica Shale 189
 318
 (40.6)% 658
 774
 (15.0)%
Total 8,509
 6,004
 41.7 % 23,172
 15,771
 46.9 %
Average crude oil equivalent per day (Boe)            
Wattenberg Field 77,582
 61,804
 25.5 % 72,545
 54,733
 32.5 %
Delaware Basin 12,845
 —
 *
 9,923
 —
 *
Utica Shale 2,064
 3,459
 (40.3)% 2,412
 2,825
 (14.6)%
Total 92,491
 65,263
 41.7 % 84,880
 57,558
 47.5 %
Midstream Capacity
* Percentage change is not meaningful.
Amounts may not recalculate dueOur ability to rounding.

Inmarket our production depends substantially on the Wattenberg Field, we rely on third-party midstream service providers to constructavailability, proximity and capacity of in-field gathering systems, compression, and processing facilities, to keep pace with ouras well as transportation pipelines out of the basin, all of which are owned and the overall field's natural gas production growth. From time-to-time,operated by third parties. If adequate midstream facilities and services are not available on a timely basis and at acceptable costs, our production has beenand results of operations could be adversely affected by high line pressures on the gas gathering facilities, primarily due to higher ambient temperatures and increases in field-wide production volumes. As a result, we have experienced some productionaffected.
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curtailments from time to time, including in the third quarter of 2017. We believe that our 2017 production guidance range appropriately reflects the impact of such higher gathering system line pressures. Our primary midstream service provider has added some additional capacity to its system in 2017, and cooler weather is expected to help increase the efficiency of the system in the fourth quarter of 2017. For the nine months ended September 30, 2017, 93 percent of our production in the Wattenberg Field was delivered from horizontal wells, with the remaining seven percent coming from vertical wells. The horizontal wells are less prone to issues than the vertical wells in that they are newer and have greater producing capacity and higher formation pressures, and therefore tend to be more resilient to gas system pressure issues. While this will lessen the impact of the pressures, we expect to continue to operate in a constrained environment through the first nine months of 2018, at which time additional processing capacity is scheduled to be brought into operation by our primary midstream provider.

We continue to work closely with our third-party midstream providers in an effort to ensure that adequate midstream system capacity is available going forward in the Wattenberg Field. We along with other operators made a commitment with DCP Midstream, LP ("DCP") to support DCP's construction of two additional processing facilities with associated gathering pipe and compression in the field. These expansions are expected to increase DCP's system capacity, assist in the control of line pressures on its natural gas gathering facilities, and reduce production curtailments in the field. We will be bound to the incremental volume requirements in these agreements on the first day of the calendar month after the actual in-service dates of the plants, which are currently scheduled to occur in the fourth quarter of 2018 and April 2019. We are currently working with DCP to identify opportunities to accelerate the completion of the first of these facilities. The agreements impose a baseline volume commitment and a guarantee of a certain target profit margin to DCP on those volumes during the initial three years of the contracts. Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments, and we believe that the contractual target profit margin will be achieved without additional payment from us. See footnote titled Commitments and Contingencies for additional details regarding the agreements. We also continue to work with all of our midstream service providers in the field in an effort to ensure all of the existing infrastructure is fully utilized and that all options for system expansions are evaluated and implemented, where possible.


The ultimate timing and availability of adequate infrastructure is not withinremains out of our controlcontrol. Weather, regulatory developments and ifother factors also affect the adequacy of midstream infrastructure. Like other producers, from time to time, we enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity to sufficiently meet our midstream service providers' construction projects are delayed,projected volume growth from our areas of operation. If our production falls below the level required under these agreements, we could experience higher gathering line pressures that may negatively impact our abilitybe subject to fulfill our growth plans. Total system infrastructure performance may also be affected by a number of other factors, including potential additional increasestransportation charges or aid in construction payments for commitment shortfalls.

Our production from the Wattenberg Field.Field and Delaware Basin was not materially affected by midstream or downstream capacity constraints during the nine months ended September 30, 2021. We continuously monitor infrastructure capacities versus producer activity and production volume forecasts.


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Crude Oil, Natural Gas and NGLs Pricing


Our results of operations depend upon many factors. Key factors include the pricemarket prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLNGLs prices have a high degree of volatility and our realizations can change substantially. Our salesweighted-average realized commodity prices for crude oil, natural gas,increased 111 percent and NGLs increased110 percent during the three and nine months ended September 30, 20172021, respectively, compared to the three and nine months ended September 30, 2016.2020. The NYMEX average daily crude oil prices increased sevenby72 percent and 2069 percent respectively, and NYMEX natural gas prices increased sevenpercent and 38 percent, respectively, as compared tofor the three and nine months ended September 30, 2016.2021, respectively. The NGLNYMEX first-of-the-month natural gas prices inincreased by103 percent and 69 percent for the Wattenberg Field are reflected in the tables below, net of the processingthree and transport costs that are embedded in the applicable percent-of-proceeds contracts, as are a portion of our Delaware Basin NGL sales.nine months ended September 30, 2021, respectively.


The following tables presenttable presents weighted-average sales prices of crude oil, natural gas and NGLs for the periods presented. Our acquisitions of assets in the Delaware Basin closed in December 2016; therefore, there is no comparative data for the three and nine months ended September 30, 2016:presented:
Three Months Ended September 30,Nine Months Ended September 30,
Weighted-Average Realized Sales Price by Operating RegionPercent ChangePercent Change
(excluding net settlements on derivatives)2021202020212020
Crude oil (per Bbl)
Wattenberg Field$69.40 $37.52 85 %$63.94 $32.28 98 %
Delaware Basin68.24 37.33 83 %64.31 34.09 89 %
Weighted-average price69.17 37.49 85 %64.00 32.59 96 %
Natural gas (per Mcf)
Wattenberg Field$2.94 $1.12 163 %$2.54 $1.04 144 %
Delaware Basin3.39 0.34 *2.52 0.17 *
Weighted-average price3.00 1.00 200 %2.54 0.91 179 %
NGLs (per Bbl)
Wattenberg Field$26.88 $9.70 177 %$22.32 $7.87 184 %
Delaware Basin39.43 11.50 243 %33.08 9.48 249 %
Weighted-average price28.33 9.97 184 %23.41 8.12 188 %
Crude oil equivalent (per Boe)
Wattenberg Field$36.14 $17.70 104 %$31.90 $15.60 104 %
Delaware Basin45.35 18.24 149 %39.01 15.73 148 %
Weighted-average price37.47 17.79 111 %32.82 15.62 110 %
  Three Months Ended September 30, Nine Months Ended September 30,
 Weighted-Average Realized Sales Price by Operating Region     Percentage Change     Percentage Change
(excluding net settlements on derivatives) 2017 2016  2017 2016 
Crude oil (per Bbl)            
Wattenberg Field $45.80
 $42.29
 8.3% $46.84
 $37.42
 25.2%
Delaware Basin 45.06
 —
 *
 46.05
 —
 *
Utica Shale 43.03
 38.93
 10.5% 44.51
 35.61
 25.0%
Weighted-average price 45.66
 42.11
 8.4% 46.69
 37.33
 25.1%
 Natural gas (per Mcf)            
Wattenberg Field $2.09
 $2.08
 0.5% $2.23
 $1.63
 36.8%
Delaware Basin 2.74
 —
 *
 2.13
 —
 *
Utica Shale 1.81
 1.33
 36.1% 2.56
 1.44
 77.8%
Weighted-average price 2.17
 2.04
 6.4% 2.23
 1.62
 37.7%
NGLs (per Bbl)            
Wattenberg Field $17.49
 $11.07
 58.0% $16.68
 $10.32
 61.6%
Delaware Basin 20.87
 —
 *
 20.02
 —
 *
Utica Shale 22.00
 12.14
 81.2% 22.40
 12.22
 83.3%
Weighted-average price 18.11
 11.12
 62.9% 17.24
 10.41
 65.6%
Crude oil equivalent (per Boe)            
Wattenberg Field $27.33
 $23.77
 15.0% $27.44
 $20.83
 31.7%
Delaware Basin 28.07
 —
 *
 27.65
 —
 *
Utica Shale 23.75
 20.98
 13.2% 26.98
 20.26
 33.2%
Weighted-average price 27.35
 23.62
 15.8% 27.45
 20.80
 32.0%
____________
* PercentagePercent change is not meaningful.
Amounts may not recalculate due to rounding.

During the three months ended September 30, 2017, the weighted-average realized sales price forCrude oil, natural gas in the Delaware Basin was impacted by the entry into aand NGLs revenues are recognized when we transfer control of crude oil, natural gas gathering contract that we accounted for underor NGLs production to the gross methodpurchaser. We consider the transfer of accounting; therefore, our realized price was based oncontrol to occur when the gross selling price.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.


Our crude oil, natural gas and NGLs sales are recorded underusing either the “net-back” or "gross"“gross” method of accounting, depending upon the related purchase agreement. We use the net-back method when control of accounting forthe crude oil, natural gas andor NGLs as well as the majority of our crude oil production from the Wattenberg Field, for all of our crude oil, NGLs, and a portion of our natural gas in the Delaware Basin, and for crude oil from the Utica Shale, ashas been transferred to the purchasers of these commodities also providethat 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 oura sales price fixed at index less specified deductions. We sell our commodities at the wellhead, or what is equivalent to the wellhead in situations where we gather multiple wells into larger pads, and collect a price and recognize revenues based on the wellhead sales price, as transportation and processing costs downstream of the wellhead are incurred by the purchaser and therefore embedded in the wellhead price. The net-back method results in the recognition of a net sales
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price that is lower than the indices forindex on which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we earn.

are paid. We use the gross method of accounting for Wattenberg Fieldwhen control of the crude oil, delivered through certain pipelines, a portion of our natural gas inor NGLs is not transferred to the Delaware Basin,purchaser and for natural gas and NGLs sales related to production from the Utica Shale, as the purchasers dopurchaser 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 transporttransportation and processing based on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses.(“TGP”) expense.


As discussed above, we enter into agreements for the sale and transportation, gathering, and processing of our production, the terms of which can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. Information related to the components and classifications inof TGP expense on the condensed consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based uponon average daily prices throughout each month and, ourfor natural gas, the average NYMEX pricing is based uponon first-of-the-month index prices, as in each case this is the method used to sell the majority of each of these commodities pursuant to terms of the respectiverelevant sales agreements. For
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PDC ENERGY, INC.
NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price both before and after transportation, gathering and processing expensesexpense shown in the table below represents our approximate composite per barrel price for NGLs.

For the three months ended
September 30, 2017
 Average NYMEX Price Average Realization Percentage Before Transportation, Gathering and Processing Expenses Average Realized Price Before Transportation, Gathering and Processing Expenses Average Transportation, Gathering and Processing Expenses Average Realized Price After Transportation, Gathering and Processing Expenses
Three Months Ended September 30, 2021Three Months Ended September 30, 2021Average NYMEX PriceAverage Realized Price Before TGP ExpenseAverage Realization Percentage Before TGP Expense
Average TGP Expense (1)
Average Realized Price After TGP ExpenseAverage Realization Percentage After TGP Expense
Crude oil (per Bbl) $48.20
 95% $45.66
 $1.41
 $44.25
Crude oil (per Bbl)$70.56 $69.17 98 %$3.13 $66.04 94 %
Natural gas (per MMBtu) 3.00
 72% 2.17
 0.24
 1.93
Natural gas (per MMBtu)4.01 3.00 75 %0.14 2.86 71 %
NGLs (per Bbl) 48.20
 38% 18.11
 0.25
 17.86
NGLs (per Bbl)70.56 28.33 40 %— 28.33 40 %
Crude oil equivalent (per Boe) 36.92
 74% 27.35
 1.15
 26.20
Crude oil equivalent (per Boe)51.89 37.47 72 %1.35 36.12 70 %
          
For the three months ended
September 30, 2016
 Average NYMEX Price Average Realization Percentage Before Transportation, Gathering and Processing Expenses Average Realized Price Before Transportation, Gathering and Processing Expenses Average Transportation, Gathering and Processing Expenses Average Realized Price After Transportation, Gathering and Processing Expenses
Three Months Ended September 30, 2020Three Months Ended September 30, 2020Average NYMEX PriceAverage Realized Price Before TGP ExpenseAverage Realization Percentage Before TGP Expense
Average TGP Expense (1)
Average Realized Price After TGP ExpenseAverage Realization Percentage After TGP Expense
Crude oil (per Bbl) $44.94
 94% $42.11
 $1.52
 $40.59
Crude oil (per Bbl)$40.93 $37.49 92 %$3.00 $34.49 84 %
Natural gas (per MMBtu) 2.81
 73% 2.04
 0.08
 1.96
Natural gas (per MMBtu)1.98 1.00 51 %0.12 0.88 44 %
NGLs (per Bbl) 44.94
 25% 11.12
 0.29
 10.83
NGLs (per Bbl)40.93 9.97 24 %— 9.97 24 %
Crude oil equivalent (per Boe) 34.48
 69% 23.62
 0.84
 22.78
Crude oil equivalent (per Boe)29.50 17.79 60 %1.30 16.49 56 %

Nine Months Ended September 30, 2021Average NYMEX PriceAverage Realized Price Before TGP ExpenseAverage Realization Percentage Before TGP Expense
Average TGP Expense (1)
Average Realized Price After TGP ExpenseAverage Realization Percentage After TGP Expense
Crude oil (per Bbl)$64.82 $64.00 99 %$3.25 $60.75 94 %
Natural gas (per MMBtu)3.18 2.54 80 %0.12 2.42 76 %
NGLs (per Bbl)64.82 23.41 36 %— 23.41 36 %
Crude oil equivalent (per Boe)45.92 32.82 71 %1.33 31.49 69 %
Nine Months Ended September 30, 2020Average NYMEX PriceAverage Realized Price Before TGP ExpenseAverage Realization Percentage Before TGP Expense
Average TGP Expense (1)
Average Realized Price After TGP ExpenseAverage Realization Percentage After TGP Expense
Crude oil (per Bbl)$38.32 $32.59 85 %$2.11 $30.48 80 %
Natural gas (per MMBtu)1.88 0.91 48 %0.12 0.79 42 %
NGLs (per Bbl)38.32 8.12 21 %— 8.12 21 %
Crude oil equivalent (per Boe)27.55 15.62 57 %1.02 14.60 53 %
____________
(1)Average TGP expense excludes unutilized firm transportation fees of $0.07 per Boe and $0.08 per Boe for the three months ended September 30, 2021 and 2020, respectively, and $0.10 per BOE and$0.04 per BOE for the nine months ended September 30, 2021 and 2020, respectively.

Our average realization percentages for crude oil, natural gas and NGLs increased for the three and nine months ended September 30, 2021 as compared to the same period in 2020 primarily due to the overall increase in commodity prices between periods driven by the improvement in oil and gas product demand that occurred throughout 2020 and 2021. Additionally, we realized improved differentials resulting from 2021 sales contracts.

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For the nine months ended
September 30, 2017
 Average NYMEX Price Average Realization Percentage Before Transportation, Gathering and Processing Expenses Average Realized Price Before Transportation, Gathering and Processing Expenses Average Transportation, Gathering and Processing Expenses Average Realized Price After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl) $49.47
 94% $46.69
 $1.42
 $45.27
Natural gas (per MMBtu) 3.17
 70% 2.23
 0.15
 2.08
NGLs (per Bbl) 49.47
 35% 17.24
 0.29
 16.95
Crude oil equivalent (per Boe) 37.99
 72% 27.45
 0.96
 26.49
           
For the nine months ended
September 30, 2016
 Average NYMEX Price Average Realization Percentage Before Transportation, Gathering and Processing Expenses Average Realized Price Before Transportation, Gathering and Processing Expenses Average Transportation, Gathering and Processing Expenses Average Realized Price After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl) $41.33
 90% $37.33
 $1.56
 $35.77
Natural gas (per MMBtu) 2.29
 71% 1.62
 0.08
 1.54
NGLs (per Bbl) 41.33
 25% 10.41
 0.29
 10.12
Crude oil equivalent (per Boe) 30.61
 68% 20.80
 0.86
 19.94

Commodity Price Risk Management Net


We use commodity derivative instruments to manage fluctuations in crude oil and natural gas and NGLs prices. We have in place a variety ofprices, including collars, fixed-price swaps,exchanges, and basis swapsprotection exchanges on a portion of our estimated crude oil and natural gas and propane production. Because we sell all of our crude oil, natural gas, and NGLs production at prices related to the indexes inherent to our underlying derivative instruments, we ultimately realize value related to our collars of no less than the floor and no more than the ceiling. For our commodity swaps,exchanges, we ultimately realize the fixed price value related to the swaps. See the footnote titled Note 5 - Commodity Derivative Financial Instruments in Item 1. Financial Statements included elsewhere in this report for a detailed presentationsummary of our derivative positions as of September 30, 2017.2021.


Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, as well asand the change in fair value of unsettled commodity derivatives related to our crude oil and natural gas and propane production. Commodity price risk management, net, does not include derivative transactions related to our gas marketing, which are included in other income and other expenses.


Net settlements of commodity derivative instruments are based on the difference between the crude oil and natural gas and propane index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net value increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The corresponding impact of settlement of the commodity derivative instruments during the period is included in net settlements for the period. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas and NGLs forward price curves and changes in certain differentials.
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The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net:

Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil collars and fixed price exchanges$(98.0)$69.7 $(166.4)$231.7 
Natural gas collars and fixed price exchanges(32.6)2.3 (40.1)5.9 
Natural gas basis protection exchanges1.0 (5.1)(8.9)(10.1)
Total net settlements of commodity derivative instruments(129.6)66.9 (215.4)227.5 
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments132.9 (75.9)20.4 (9.5)
Crude oil collars and fixed price exchanges(82.4)(25.2)(326.0)83.9 
Natural gas collars and fixed price exchanges(137.1)(24.4)(185.0)(37.5)
Natural gas basis protection exchanges(1.5)(9.5)(1.2)(18.5)
Net change in fair value of unsettled commodity derivative instruments(88.1)(135.0)(491.8)18.4 
Total commodity price risk management gain (loss), net$(217.7)$(68.1)$(707.2)$245.9 

 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Commodity price risk management gain (loss), net:       
Net settlements of commodity derivative instruments:       
Crude oil fixed price swaps and collars$5.4
 $39.5
 $7.4
 $131.6
Natural gas fixed price swaps and collars5.1
 7.7
 13.5
 35.8
Natural gas basis protection swaps1.2
 0.5
 3.3
 0.5
NGLs (propane portion) fixed price swaps(2.1) —
 (2.0) —
Total net settlements of commodity derivative instruments9.6
 47.7
 22.2
 167.9
Change in fair value of unsettled commodity derivative instruments:       
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments(15.6) (40.6) 31.0
 (169.5)
Crude oil fixed price swaps and collars(40.0) 4.8
 26.3
 (48.3)
Natural gas fixed price swaps and collars(2.1) 6.1
 9.2
 (13.1)
Natural gas basis protection swaps1.5
 1.4
 3.4
 0.7
NGLs (propane portion) fixed price swaps(5.6) —
 (5.6) —
Net change in fair value of unsettled commodity derivative instruments(61.8) (28.3) 64.3
 (230.2)
Total commodity price risk management gain (loss), net$(52.2) $19.4
 $86.5
 $(62.3)

Net settlements of commodity derivatives decreased for the three and nine months ended September 30, 2017, as compared to the three and nine months ended September 30, 2016.  We entered into agreements for the derivative instruments that settled throughout 2016 prior toThe significant movement in commodity prices becoming depressed in late 2014.  Substantially all of these higher-value agreements had settled by the end of 2016.  Net settlements for the three and nine months ended September 30, 2017, reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices.  Based upon the forward strip pricing at September 30, 2017, we expect that settlements will continue to be substantially lower in 2017 on a relative basis as compared to those in 2016.

Lease Operating Expenses

Lease operating expenses increased to $2.98 per Boe and $2.81 per Boe during the three and nine months ended September 30, 2017, respectively, compared2021 had an overall unfavorable impact on the fair values and settlements of our commodity derivatives.

Lease Operating Expense

Lease operating expense (“LOE”) increased by 22 percent to $2.33 per Boe and $2.73 per Boe during the three and nine months ended September 30, 2016, respectively. Our lease operating expenses per Boe were $2.50 per Boe during the three months ended June 30, 2017 and $2.98 per Boe during the three months ended March 31, 2017. Our per Boe costs have increased compared to prior year periods primarily due to the expected higher per Boe costs in the Delaware Basin. The per Boe costs during$45.6 million for the three months ended September 30, 2017 increased as2021 compared to $37.3 million for the three months ended September 30, 2016,2020. The period-over-period increase in LOE was primarily dueattributable to increases(i) increased activities and payroll costs at our well locations from the COVID-19 induced downturn in 2020, (ii) $2.5 million of $0.19 per Boeenvironmental and regulatory costs incurred in the third quarter of 2021, and (iii) vendor concessions experienced for water disposal, $0.15 per Boe for environmental remediation costs, and $0.14 per Boe for increased workover projects.

Aggregate lease operating expenses during the three months ended September 30, 2017,2020. LOE per Boe increased $11.4 million as compared15 percent to $2.43 for the three months ended September 30, 2016, of which $7.22021 from $2.11 for the three months ended September 30, 2020.

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LOE increased by 6 percent to $129.8 million related to our properties in the Delaware Basin.The increase of $11.4 million is primarily due to increases of $2.9 million for payroll and employee benefits related to increases in headcount, $1.9 million for produced water disposal, $1.8 million for increased workover projects, $1.5 million for environmental remediation costs, and $1.3 million related to additional compressor rentals to combat increased gathering system line pressures.

Aggregate lease operating expenses during the nine months ended September 30, 2017, increased $22.22021 compared to $122.7 million as compared tofor the nine months ended September 30, 2016,2020. The period-over-period increase in LOE was primarily due to(i) increased activities and payroll costs at our well locations from the COVID-19 induced downturn in 2020, (ii) $3.5 million of which $15.6 million related to our propertiesenvironmental and regulatory costs incurred in the Delaware Basin. The increasefirst nine months of $22.2 million is primarily due2021, and (iii) fewer vendor concessions experienced for the nine months ended September 30, 2021 as compared to increasesthe same period in 2020 as the price of $7.2 millioncommodities has improved. LOE per Boe increased 5 percent to $2.50 for payroll and employee benefits related to increases in headcount, $3.7 millionthe nine months ended September 30, 2021 from $2.37 for produced water disposal, $3.5 million for workover projects, $3.1 million related tothe nine months ended September 30, 2020.
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additional compressor rentals to combat increased gathering system line pressures, and $2.5 million related to vehicle and equipment expenses. We expect continued increases in our headcount through the remainder of 2017 as we grow our Delaware Basin production base and production team. On a per unit basis, we expect much of this increased cost of personnel will be offset by increases in our production.


Production Taxes


Production taxes are comprised mainly of severance tax and ad valorem tax, and are directly related to crude oil, natural gas and NGLs sales and are generally assessed as a percentage of net revenues. From time-to-time,time to time, there are adjustments to the statutory rates for these taxes based upon certain credits that are determined based upon activity levels and relative commodity prices from year-to-year.

Production taxes increased 205 percent to $44.7 million for the three months ended September 30, 2021 compared to $14.6 million for the three months ended September 30, 2020. Production taxes per Boe increased 187 percent to $2.38 for the three months ended September 30, 2021 compared to $0.83 for the three months ended September 30, 2020. The $5.9 million and $23.3 million increasesincrease in production taxes was primarily due to an increase in crude oil, natural gas and NGLs prices between periods.

Production taxes increased 147 percent to $101.1 million for the nine months ended September 30, 2021 compared to $40.9 million for the nine months ended September 30, 2020. Production taxes per Boe increased 147 percent to $1.95 for the nine months ended September 30, 2021 compared to $0.79 for the nine months ended September 30, 2020. The increase in production taxes was primarily due to an increase in crude oil, natural gas and NGLs prices between periods.

Transportation, Gathering and Processing Expense

TGP expense increased 10 percent to $26.7 million for the three months ended September 30, 2021 compared to $24.4 million for the three months ended September 30, 2020. TGP expense per Boe increased 3 percent to $1.42 for the three months ended September 30, 2021 compared to $1.38 for the three months ended September 30, 2020. The increase in TGP expense was primarily due to a 6 percent increase in production volumes between periods.

TGP expense increased 36 percent to $74.5 million for the nine months ended September 30, 2021 compared to $54.8 million for the nine months ended September 30, 2020. TGP expense per Boeincreased 35 percent to $1.43 for the nine months ended September 30, 2021 compared to $1.06 for the nine months ended September 30, 2020. The overall increase in TGP expense for the nine months ended September 30, 2021 compared to the same period in 2020 was driven by a $14.5 million increase relating to transportation of our crude oil volumes delivered and $3.0 million of shortfall fees relating to our delivery commitment in the Delaware Basin. These increases were partially offset by a decrease in natural gas production in the Delaware Basin for the first nine months of 2021 compared to the same period in 2020.

Impairment of Properties and Equipment
There were no significant impairment charges recognized related to our proved and unproved oil and gas properties during the three and nine months ended September 30, 2017, respectively, compared to the three and nine months ended September 30, 2016 were primarily related to the 64 percent and 94 percent increases in2021. If crude oil naturalprices decline, or we change other estimates impacting future net cash flows (e.g. reserves, price differentials, future operating and/or development costs), our proved and unproved oil and gas and NGLs sales.

Transportation, Gathering, and Processing Expenses

Transportation, gathering, and processing expenses increased $4.7 million and $8.6 million during the three and nine months ended September 30, 2017, respectively, comparedproperties could be subject to the three and nine months ended September 30, 2016. The primary drivers of these increases were $1.3 million and $3.7 million increases in oil transportation costs due to increased volumes delivered through a pipeline in the Wattenberg Field and increases of $3.8 million and $5.2 million, respectively, related to natural gas gathering and transportation operations in the Delaware Basin. The increases during the three and nine months ended September 30, 2017 were slightly offset by decreases related to lower production in the Utica Shale. When feasible, we use pipelines in the Wattenberg Field to deliver crude oil to the market in an effort to decrease field truck traffic and air emissions. Transportation, gathering, and processing expenses per Boe increased to $1.15 and $0.96 for the three and nine months ended September 30, 2017, respectively, compared to $0.84 and $0.86 for the three and nine months ended September 30, 2016, respectively. As disclosed previously in this section, there is an interaction with the marketing contracts in determining if transportation, gathering, and processing costs are presented separately or presented net in the revenue section of our financial statements; therefore, the net realized price analysis is a useful analysis to understand our net realized prices.

Exploration, Geologic, and Geophysical Expense

The following table presents the major components of exploration, geologic, and geophysical expense:
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
        
Exploratory dry hole costs$41.2
 $—
 $41.2
 $—
Geological and geophysical costs, including seismic purchases0.5
 —
 1.8
 —
Operating, personnel and other0.2
 0.2
 0.9
 0.7
Total exploration, geologic, and geophysical expense$41.9
 $0.2
 $43.9
 $0.7
        

Exploratory dry hole costs. During the three and nine months ended September 30, 2017, two exploratory dry hole wells, associated lease costs, and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.2 million. The conclusion to expense these items was due to the determination that the acreage on which these wells were drilled was exploratory in nature and, following drilling, the lack of hydrocarbon production necessary for the wells to be deemed economically viable.
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Impairment of Properties and Equipment
The following table sets forth the major components of our impairment of properties and equipment expense:

 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
        
Impairment of unproved properties$252.6
 $0.3
 $282.2
 $2.4
Amortization of individually insignificant unproved properties0.1
 0.6
 0.3
 0.7
Impairment of crude oil and natural gas properties
252.7
 0.9
 282.5
 3.1
Land and buildings—
 —
 —
 3.0
Total impairment of properties and equipment$252.7
 $0.9
 $282.5
 $6.1

Impairment of unproved properties. Amounts represent the retirement or expiration of certain leases that are no longer part of our development plan or that we do not plan to extend and will allow to expire. Deterioration of commodity prices or other operating circumstances could result in additional impairment charges as such a change could decrease the number of wells drilledimpairments in future periods.


During the three months ended September 30, 2017,March 31, 2020, we recorded a charge related to two exploratory dry holes we had drilled in the western areaimpairment charges of our Culberson County acreage in the Delaware Basin, as referenced previously.  We then assessed the impact of the dry holes and various factors related thereto, including (i) the operational and geologic data obtained, (ii) the current increased cost environment for drilling and completion services in the Delaware, (iii) our decreased future commodity price outlook, and (iv) the terms of  the related lease agreements.  Based on the results of this assessment, we concluded that the underlying geologic risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage.  Accordingly, we recorded an$881.1 million. The impairment of $251.6 million covering approximately 13,400 acrescharges during the third quarter of 2017.  The amount of the impairment was based on the value assigned to individual lease acres in the final purchase price allocation of the business combination.  This allocation had included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. Due to the aforementioned events and circumstances in the third quarter of 2017, we evaluated our proved property for possible impairment and concluded that these assetsthree months ended March 31, 2020 were not impaired during the period.

Impairment of Goodwill

The final goodwill that resulted from the purchase price allocation of the assets acquired in the Delaware Basin was determined to be $75.1 million. With the creation of goodwill from this transaction, we expected to perform our evaluation of goodwill for impairment annually in the fourth quarter. However, primarily due to a combination of increasessignificant decline in per well development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin since the time of the acquisition, in conjunction with our lower future commodity price outlook, we determinedcrude oil prices, which was considered a triggering event had occurred in the quarter ended September 30, 2017. In additionthat required us to the factors mentioned above, we also consideredassess our recent impairments of certain unproven leasehold costs,crude oil and the impact of these items on our internal expectationsnatural gas properties for acceptable rates of return. We evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill asset group, which we define as the Delaware Basin, to the carrying value. We determined the fair value of the goodwill at September 30, 2017 by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value was based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. The quantitative test resulted in a determination that a full impairment charge of $75.1 million was required; therefore, the charge was recorded in the quarter ended September 30, 2017.possible impairment.


General and Administrative Expense


General and administrative expense decreased $3.25 percent to $30.8 million for the three months ended September 30, 2017, as2021 compared to $32.5 million for the three months ended September 30, 2016. The decrease of $3.2 million was2020, primarily attributabledue to a decrease of $10.2 million in professional feespayroll and benefits related to the Delaware Basin acquisition that were incurredclosure of our Bridgeport, West Virginia office in 2016, partially offset byearly 2021.
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increases of $3.7 million in payroll and employee benefits related to an increase in headcount for 2017 as compared to 2016, $2.0 million related to professional services, and $0.8 million for adjustments to the accounts receivable allowance.

General and administrative expense increased $6.3decreased 26 percent to $96.4 million for the nine months ended September 30, 2017, as2021 compared to $130.0 million for the nine months ended September 30, 2016. The increase of $6.3 million was2020, primarily attributabledue to increases of $7.5$30.0 million in payrolltransaction and employee benefits due to an increasetransition costs incurred in headcount for 2017 as compared to 2016, $2.9 millionthe first nine months of 2020 related to professional services, $2.4 million related to legal settlements, $1.0 million in software maintenance agreements the SRC Acquisitionand subscriptions, and $1.0 million in rent expense. The increases were partially offset by a decrease of $10.2 million in professionalconsultant fees related to the Delaware Basin acquisition during the third quarterour ERP implementation of 2016. We expect continued increases in our headcount through the remainder of 2017 as we build out our Delaware Basin operations and the associated supporting service elements.$5.3 million.

Depreciation, Depletion and Amortization Expense


Crude oil and natural gas properties. DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $123.6$167.7 million and $355.7for the three months ended September 30, 2021 compared to $142.3 million for the threecomparable period in 2020. The increase in DD&A expense was primarily due to an increase in the weighted-average DD&A expense rate as a result of capitalized costs of wells turned-in-line since the third quarter of 2020 and an increase in production volumes between periods.

DD&A expense related to crude oil and natural gas properties was $472.7 millionfor the nine months ended September 30, 2017, respectively,2021 compared to $112.1 million and $314.4$463.5 million for the three and nine months ended September 30, 2016, respectively.comparable period in 2020. The increase in total DD&A expense was primarily due an increase in the weighted-average DD&A expense rate as a result of capitalized costs of wells turned-in-line since the third quarter of 2020 partially offset by the proved property impairment recognized in the first quarter of 2020 in the Delaware Basin, which lowered the carrying value of our depletion base.


The period-over-period change in DD&A expense related to crude oil and natural gas properties was primarily due to the following:
Three Months Ended September 30, 2021Nine Months Ended September 30, 2021
(in millions)
Increase (decrease) in production$9.1 $(0.6)
Increase (decrease) in weighted-average depreciation, depletion and amortization rates16.3 9.9 
Total increase (decrease) in DD&A expense related to crude oil and natural gas properties$25.4 $9.3 
  September 30, 2017
  Three Months Ended Nine Months Ended
  (in millions)
Increase in production $44.5
 $138.5
Decrease in weighted-average depreciation, depletion and amortization rates (33.0) (97.2)
Total increase in DD&A expense related to crude oil and natural gas properties $11.5
 $41.3


The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties:properties for the periods presented:

Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
(per Boe)
Operating Region/Area
Wattenberg Field$8.93 $8.33 $9.04 $8.80 
Delaware Basin9.01 6.87 9.54 10.06 
Total weighted-average8.94 8.16 9.10 9.08 
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  Three Months Ended September 30, Nine Months Ended September 30,
Operating Region/Area 2017 2016 2017 2016
  (per Boe)
Wattenberg Field $14.60
 $19.17
 $15.53
 $20.42
Delaware Basin 15.14
 —
 15.32
 —
Utica Shale 7.64
 9.59
 10.21
 10.52
Total weighted-average 14.52
 18.66
 15.35
 19.94
Interest Expense, net


DuringInterest expense, net decreased $0.9 million to $20.1 million for the three months ended September 30, 2017, as part of plans2021 compared to divest the Utica Shale properties, we engaged an investment banking group and began actively marketing the properties$21.0 million for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification at the beginning of September 2017. As a result of the properties being classified as held-for-sale, we stopped recording DD&A expense on these properties during the three month periodmonths ended September 30, 2017, which has lowered2020. The decrease was primarily related to reduced borrowings under our revolving credit facility between periods,partially offset by an increase in interest expense related to the rateissuance of an additional $150 million aggregate principal amount of the 2026 Senior Notes in September 2020.

Interest expense, net decreased $7.8 million to $59.2 million for the quarter.nine months ended September 30, 2021 compared to $67.0 million for the nine months ended September 30, 2020. The decrease was primarily related to a $10.6 million decrease due to reduced borrowings under our revolving credit facility between periods and a $2.8 million decrease related to the partial redemption in February 2020 of the 2025 Senior Notes. These decreases were partially offset by a $6.1 million increase in interest expense related to the issuance of an additional $150 million aggregate principal amount of the 2026 Senior Notes in September 2020.


Non-crude oilProvision for Income Taxes

We recorded a full valuation allowance against our net deferred tax assets for the nine months ended September 30, 2021 and natural gas properties. Depreciation expense for non-crude oil2020 resulting in an effective income tax rate of 0.1 percent and natural gas properties was $1.7 million and $4.8 million0.2 percent provision on income for the three and nine months ended September 30, 2017,2021, respectively, compared to $0.9 million and $2.9 million for the three and nine months ended September 30, 2016, respectively.

Provision for Uncollectible Notes Receivable

In the first quarter of 2016, we recorded a provision for uncollectible notes receivable of $44.7 million to impair two third-party notes receivable whose collection was not reasonably assured. As described in the footnote titled Fair Value of Financial Instruments, in April 2017, we signed a definitive agreement and simultaneously closed on the sale of one of the associated notes receivable to an unrelated third-party. Accordingly, we reversed $40.2 million of the provision for
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uncollectible notes receivable during the nine months ended September 30, 2017, since all cash was collected in April 2017 from the sale of the note.

Interest Expense

Interest expense decreased $0.9 million to $19.3 million for the three months ended September 30, 2017 compared to $20.2 million for the three months ended September 30, 2016. The decrease is primarily attributable to a $9.0 million charge for a bridge loan commitment related to acquisitions of properties in the Delaware Basin during the three months ended September 30, 2016 and a $0.4 million decrease in interest expense0.6 percent provision on our 2016 Convertible Notes, which were settled in May 2016. The decreases were partially offset by a $5.3 million increase in interest relating to the issuance of our 2024 Senior Notes, a $2.6 million increase in interest expense relating to the issuance of our 2021 Convertible Notes,loss and a $0.9 million increase related to fees for the redetermination of the borrowing base under our revolving credit facility.

Interest expense increased $15.6 million to $58.4 million for the nine months ended September 30, 2017 compared to $42.8 million for the nine months ended September 30, 2016. The increase is primarily attributable to an $18.0 million increase in interest expense relating to the issuance of our 2024 Senior Notes, a $7.7 million increase in interest expense relating to the issuance of our 2021 Convertible Notes, and a $2.5 million increase related to fees for the redetermination of the borrowing base under our revolving credit facility. These increases were partially offset by a $9.0 million charge for the bridge loan commitment related to acquisitions of properties in the Delaware Basin during the three months ended September 30, 2016 and a $3.9 million decrease in interest expense on our 2016 Convertible Notes, which were settled in May 2016.

Provision for Income Taxes

The effective income tax rates for the three and nine months ended September 30, 2017 were 29.5 percent and 25.8 percent benefit on loss, respectively, compared to 34.0 percent and 37.10.5 percent benefit on loss for the three and nine months ended September 30, 2016,2020, respectively. The most significant element related toeffective tax rate differs from the decrease inamount that would be provided by applying the effectivestatutory U.S. federal income tax rate was the impact from the impairment of the goodwill in the quarter ended September 30, 2017. This goodwill did not have an associated deferred tax liability associated with the goodwill at the time it was created, therefore, no deferred tax benefit was realized upon the impairment of the goodwill. The effective income tax rates are based upon a full year forecasted pre-tax loss for the year adjusted for permanent differences. The forecasted full year effective income tax rate has been applied to the quarter-to-date pre-tax loss, resulting in an income tax benefit for the period. Because the estimate of full-year income or loss may change from quarter to quarter, the effective income tax rate for any particular quarter may not have a meaningful relationship21 percent to pre-tax income due to the valuation allowance in effect for both periods.

At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. As of September 30, 2021, there was no change in our assessment of the realizability of our DTAs. Future events or lossnew evidence which may lead us to conclude that it is more likely than not that our net DTAs will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions.

As long as we conclude that we will continue to provide for the quarter or the actual annual effectivea valuation allowance against our net deferred tax assets, we will likely not have any income tax rate that is determined at the end of the year. In addition to the impact from the goodwill impairment, the effective income tax rateexpense or benefit other than for the three months ended September 30, 2017 includes discrete income tax benefits of $0.8 million for additional deductions and credits claimed on the filed 2016 federal and state income tax returns. The effective income tax rate for the nine months ended September 30, 2017 includes discrete income tax benefits of $1.8 million relating to the excess income tax benefit recognized with the vesting of stock awards and $0.8 million for additional deductions and credits claimed on the filed 2016 federal and state tax returns. These discrete tax benefits during the three and nine months ended September 30, 2017 resulted in a 0.2 percent and 0.9 percent increase to our effective income tax rates.taxes.


Net Income (Loss)/Adjusted Net Income (Loss)

The factors resulting in changes inimpacting net loss in the three and nine months ended September 30, 2017income of $292.5$145.3 million and $205.1 million, respectively, and a net loss in the three and nine months ended September 30, 2016 of $23.3 million and $190.3 million, respectively, are discussed above. These same reasons similarly impacted adjusted net loss, a non-U.S. GAAP financial measure, with the exception of the tax affected net change in fair value of unsettled derivatives of $38.6 million and $40.3$49.2 million for the three and nine months ended September 30, 2017,2021, respectively, and $17.5net loss of $30.8 million and $142.6$717.6 million for the three and nine months ended September 30, 2016, respectively. 2020, respectively, are discussed above.

Adjusted net loss,income, a non-U.S. GAAP financial measure, was $253.9$233.4 million and $245.4$541.0 million for the three and nine months ended September 30, 2017, respectively, and2021, respectively. We recognized an adjusted net loss was $5.8 million and $47.7income of $104.2 million for the three months ended September 30, 2020 and an adjusted net loss of $736.0 million for the nine months ended September 30, 2016, respectively.2020. With the exception of the tax-affected (when applicable) net change in fair value of unsettled commodity derivatives, the same factors impacted adjusted net income (loss). See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of thisthese non-U.S. GAAP financial measuremeasures and a reconciliation of this measurethese measures to the most comparable U.S. GAAP measure.measures.

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Financial Condition, Liquidity and Capital Resources


Overview

Our primary sources of liquidity are net cash flows from operating activities, unused borrowing capacity from our revolving credit facility, proceeds raised in debt and equity capital market transactions, and other sources, such as asset sales. For the nine months ended September 30, 2017, our net cash flows from operating activities were $411.4 million.


Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity
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prices have historically been volatile and we manage a portion of this volatility through our use of commodity derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. Based upon

We may use our hedge positionavailable liquidity for operating activities, capital investments, working capital requirements, acquisitions, capital returns and assuming forward strip pricingfor general corporate purposes. We maintain a significant capital investment program to execute our development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells. From time to time, these activities may result in a working capital deficit; however, we do not believe that our working capital deficit as of September 30, 2017, our derivatives may not be2021 is an indication of a significant sourcelack of cash flow in the near term.

Ourliquidity. We had working capital fluctuates for various reasons, including, but not limiteddeficits of $568.7 millionas of September 30, 2021 and $471.6 million as of December 31, 2020. The increase in working capital deficit since December 31, 2020 was primarily due to changesan increase in the fair value of derivative liabilities of $356.4 million partially offset by the retirement and redemption of our 2021 Convertible Notes for $200 million. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative instruments and changes in our cash and cash equivalents due to our practicehedging program, utilization of utilizing excess cash to reduce the outstanding borrowingsborrowing capacity under our revolving credit facility. At September 30, 2017,facility and, if warranted, capital markets transactions from time to time.

From time to time, we had a working capital deficitmay seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of $39.1 million compared to working capital of $129.2 million at December 31, 2016. The decreaseother debt or equity securities, in working capital as of September 30, 2017 is primarily the result of a decrease in cash and cash equivalents of $107.7 million related to capital investment exceeding operating cash flows and an increase in accounts payable of $97.8 million related to increased development and exploration activity, which was partially offset by an increase in the net fair value of our unsettled commodity derivative instruments of $41.7 million.open market purchases, privately negotiated transactions or otherwise.


Liquidity
Our cash and cash equivalents were $136.4$99.9 million at September 30, 20172021 and availability under our revolving credit facility was $700.0 million,$1.6 billion, providing for a total liquidity position of $836.4 million$1.7 billion as of September 30, 2017. Our liquidity was augmented in 2017 by2021. The borrowing base is primarily based on the $40.2 million of proceeds received inloan value assigned to the second quarter of 2017proved reserves attributable to our crude oil and natural gas interests. Based on our current production forecast for 2021, we expect 2021 cash flows from the sale of the Promissory Note, as described previously. We anticipate thatoperations to exceed our capital investments will exceed our cash flows from operating activities in 2017. With this outspend, along with the expected closing of the acquisition of certain properties owned by Bayswatercrude oil and certain related parties, we expect to have borrowings on our revolving credit facility at December 31, 2017.natural gas properties.


Based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to fund our planned activities during 2017.through the 12-month period following the filing of this report. We also believe that we will have sufficient expected cash flows from operations to allow us to repurchase additional shares pursuant to the Stock Repurchase Program and to pay potential future dividends.


Our revolving credit facility is a borrowing base facilityavailable for working capital requirements, capital investments, acquisitions, to support letters of credit and availability under the facility is subject to redetermination generally each May and November, based upon a quantification of our proved reserves at each December 31 and June 30, respectively.for general corporate purposes. The maturity date of our revolving credit facility is May 2020. Our abilitycontains 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 borrowmaintain: (a) a minimum current ratio of 1.0:1.0 and (b) a leverage ratio of not greater than 4.0:1.0. For purposes of the current ratio covenant, the revolving credit facility’s definition of total current assets, in addition to current assets as presented under U.S. GAAP, includes, among other things, unused commitments under the revolving credit facility is limited under our 2022 Senior Notes tofacility. Additionally, the greater of $700 million or the calculated value under an Adjusted Consolidated Tangible Net Asset test, as defined.

In May 2017, we entered into a Fifth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, amends the revolving credit facility to reflect an increase of the borrowing base from $700 million to $950 million. In addition, the Fifth Amendment made changes to certain of the covenants in the existing agreement as well as other administrative changes.

In October 2017, we entered into a Sixth Amendment to the Third Amended and Restated Credit Agreement. The amendment amends the revolving credit facility to allow the borrowing base to increase above the maximum allowable borrowing capacity of $1.0 billion. We have elected to increase the borrowing base to $1.1 billion for our fall 2017 borrowing base redetermination and have elected to maintain a $700 million commitment level as of the date of this report.

Amounts borrowed under the revolving credit facility bear interest at either an alternate base rate option or a LIBOR option as defined in the revolving credit facility plus an applicable margin, depending on the percentage of the commitment that has been utilized. As of September 30, 2017, the applicable margin is 1.25 percent for the alternate base rate option or 2.25 percent for the LIBOR option, and the unused commitment fee is 0.5 percent.

We had no balance outstanding on our revolving credit facility as of September 30, 2017. In May 2017, we replaced our $11.7 million irrevocable standby letter of credit that we held in favor of a third-party transportation service
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provider to secure a firm transportation obligation with a $9.3 million deposit, which is classified as restricted cash and is included in other assets on the condensed consolidated balance sheet. As of September 30, 2017, the available funds under our revolving credit facility were $700 million based on our elected commitment level.

Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain (i) a leverage ratio defined as total debt of less than 4.0 times the trailing 12 months earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled commodity derivatives, exploration expense, gains (losses) on sales of assets and other non-cash gains (losses) and (ii) an adjusted current ratio of at least 1.0:1.0. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of crude oil and natural gas commodity derivative instruments. Additionally, available borrowings under our revolving credit facility are addedcovenant calculation allows us to the current asset calculation andexclude the current portion of our revolving credit facilitylong-term debt is eliminatedand other short-term loans from the U.S. GAAP total current liabilities calculation.amount. Accordingly, the existence of a working capital deficit under U.S. GAAP is not necessarily indicative of a violation of the current ratio covenant. At September 30, 2017, we were in compliance with all debt covenants, as defined by the revolving credit agreement, with a leverage ratio of 1.8 and a current ratio of 2.9. We expect to remain in compliance throughout the next 12-month period.

The indentures governing our 2022 Senior Notes and 2024 Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt including under our revolving credit facility, (b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem, or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates, and (g) merge or consolidate with another company. At September 30, 2017,2021, we were in compliance with all covenants in the revolving credit facility with a current ratio of 3.5:1.0 and a leverage ratio of 0.9:1.0.

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On November 2, 2021, we entered into a Fifth Amended and Restated Credit Agreement (the “New Credit Facility”) on substantially similar terms as those in our existing revolving credit facility. The New Credit Facility, led by JPMorgan Chase Bank, provides for an aggregate maximum credit amount of $2.5 billion, has an initial borrowing base of $2.4 billion and matures in November 2026. We elected an initial commitment amount of $1.5 billion. Other significant changes in terms include: (i) a decrease in the maximum leverage ratio from 4.0:1.00 to 3.50:1.00; (ii) replacement of all provisions and related definitions regarding LIBOR with a Secured Overnight Financing Rate based benchmark rate (“SOFR”); (iii) the ability to add certain sustainability-linked key performance indicators to be agreed upon between parties that may impact the applicable margin and commitment fee rate; (iv) the addition of an investment grade period election pursuant to which we have an option to remove our borrowing base limitations and terminate the liens securing the New Credit Facility when certain debt ratings are achieved; and (v) changes to certain of our covenant baskets and event of default provisions.

In October 2021, we notified the trustee of our 2024 Senior Notes of our intention to redeem approximately $200 million in aggregate principal amount of the notes at a redemption price of 101.531% of the principal plus accrued and unpaid interest. We made our payment on November 3, 2021, leaving an aggregate principal amount outstanding of $200 million.In addition, in October 2021, we notified the trustee of our 2025 Senior Notes of our intention to redeem all of the remaining outstanding principal amount of $102.3 million at a redemption price of 103.125 percent of the principal plus accrued and unpaid interest. We expect to repay our 2025 Senior Notes on December 1, 2021.

We expect to remain in compliance with the covenants under our credit facility and our Senior Notes throughout the next 12-month period.

In January 2017, pursuant toperiod following the filing of the supplemental indentures for the 2021 Convertible Senior Notes, the 2022 Senior Notes, and the 2024 Senior Notes, our subsidiary PDC Permian, Inc. became a guarantor of the notes.this report.


Cash Flows


Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs, and general and administrative expenses.expense. Cash flows from operating activities increased by $50.6 million to $411.4$378.5 million for the nine months ended September 30, 20172021 compared to the nine months ended September 30, 2016,2020. The increase between periods was primarily due to increasesa $895.2 million increase in revenue from crude oil, natural gas and NGLs sales, a $33.6 million decrease in general and administrative expense, and the timing of $308.0 million.vendor payments. These increases were partially offset in part by a decrease $215.4 millionin cash settlement losses on commodity derivatives in the first nine months of 2021 compared to a $227.5 million in cash receipts from derivative settlements of $145.7in the comparable period in 2020, a$60.2 millionincrease in production taxes and a decrease in changes in assets and liabilities of $30.8 million related to the timing of cash payments and increases in production taxes of $23.3 million, lease operating expenses of $22.2 million, interest expense of $15.6 million, transportation, gathering, and processing expenses of $8.6 million, and general and administrative expenses of $6.3 million.receivable collections between periods.


Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $81.3 million to $407.5$406.7 million during the nine months ended September 30, 2017 compared2021 to $1,059.5 million from $652.8 million during the nine months ended September 30, 2016.2020. The increase was primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of assets and liabilities. Adjusted EBITDAX,free cash flow, a non-U.S. GAAP financial measure, increased by $184.3$370.8 million during the nine months ended September 30, 2017,2021 to $609.5 million compared to the nine months ended September 30, 2016. The increase was primarily the result of increases in crude oil, natural gas and NGLs sales of $308.0 million, the recording of a provision for uncollectible notes receivable of $44.7$238.7 million during the nine months ended September 30, 2016,2020. The increase between periods was primarily due to the increase in cash flows from operating activities, as discussed above, and the reversal of a provision for uncollectible notes receivable of $40.2 million during the nine months ended September 30, 2017.  These increases were partially offset by a decrease in commodity derivative settlements of $145.7 millioncapital investments in crude oil and increases in production taxes of $23.3 million, lease operating expenses of $22.2 million, transportation, gathering, and processing expenses of $8.6 million, and general and administrative expenses of $6.3 million.natural gas properties.

 See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.


Investing Activities. BecauseAs crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments.


Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties.Net cash used in investing activities of $512.8$424.5 million during the nine months ended September 30, 2017,2021 was primarily related to cash utilized for our drilling operations, includingand completion activities of $528.9$428.8 million, $21.0partially offset by $4.7 million deposit toward the purchase price of the acquisition of certain
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properties owned by Bayswater and certain related parties, purchases of short-term investments of $49.9 million, and a $9.3 million deposit with a third-party transportation service provider for surety of an existing firm transportation obligation previously secured by a letter of credit.  Partially offsetting these investments was the receipt of approximately $49.9 million related to the sale of short-term investments, $40.2 millionin proceeds from the sale of the Promissory Note,certain properties and $5.4 million related to post-closing settlements of properties acquired in 2016.

Financing Activities. equipment. Net cash from financingused in investing activities forof $583.9 million during the nine months ended September 30, 2017 decreased by approximately $1,291.12020 was primarily related to our drilling and completion activities of $445.5 million comparedand $139.8 million related to the closing of the SRC Acquisition.

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Financing Activities. Net cash used in financing activities of $506.0 million during the nine months ended September 30, 2016. Certain capital markets2021 was primarily due to net repayments on our credit facility of $168.0 million, redemption and financing activities occurred in 2016 including $855.1retirement of our 2021 Convertible Notes for $200 million, received from an issuancethe repurchase of 2.7 million shares of our common stock $392.3for $107.3 million pursuant to our Stock Repurchase Program and dividend payments totaling $23.6 million. Repurchases of our common stock may extend into 2023 based on current market conditions, although the board of directors could elect to suspend or terminate the program at any time, including if certain share price parameters are not achieved. As of September 30, 2021, $238.5 millionout of the approved $525 million remained available for repurchases under the program. Further, in the second and third quarter of 2021, our board of directors declared and paid total cash dividends of$0.24 per common share. Future repurchases of common stock or dividend payments will be subject to approval by our board of directors and depend on our level of earnings, financial requirements, and other factors considered relevant by our board.

Net cash used in financing activities of $62.5 million during the nine months ended September 30, 2020 was a result of the redemption of a portion of the 2025 Senior Notes totaling $452.2 million and the repurchase and retirement of 1.3 million shares of our common stock totaling $23.8 million pursuant to our Stock Repurchase Program. These transactions were financed by our net borrowings under our credit facility of $281.0 million, proceeds from the issuance of the2026 Senior Notes of $148.5 million and cash flows from our operating activities.

Subsidiary Guarantor

PDC Permian, Inc., a Delaware corporation (the “Guarantor”), our wholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes, 2025 Senior Notes and 2026 Senior Notes (collectively, the “Senior Notes”). The Guarantor holds our assets located in the Delaware Basin. The Senior Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantees are subject to release in limited circumstances only upon the occurrence of certain customary conditions.

The indentures governing the Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the $194.0 millionability of proceeds from the issuance of the 2021 Convertible Notes. These amounts were partially offset by the $115.0 million payment of principal amounts owed upon the maturity of the 2016 Convertible Notes and net payments of approximately $37.0 million to pay down amounts borrowedour restricted subsidiaries to: (i) incur additional debt including under our revolving credit facility, (ii) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (ii) sell assets, including capital stock of our restricted subsidiaries, (iv) restrict the payment of dividends or other payments by restricted subsidiaries to us, (v) create liens that secure debt, (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.

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PDC ENERGY, INC.
The following summarized subsidiary guarantor financial information has been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the first quarter of 2016.equity method.

As of/Nine Months EndedAs of/Year Ended
September 30, 2021December 31, 2020
IssuerGuarantorIssuerGuarantor
(in millions)
Assets
Current assets$428.0 $56.2 $271.4 $(57.8)
Intercompany accounts receivable, guarantor subsidiary25.4 — 107.3 — 
Investment in guarantor subsidiary1,767.2 — 1,767.2 — 
Properties and equipment, net3,888.8 937.5 3,982.1 877.1 
Other non-current assets51.6 4.6 56.6 4.3 
Liabilities
Current liabilities$985.4 $68.1 $751.3 $28.5 
Intercompany accounts payable— 12.0 — 94.2 
Long-term debt1,243.2 — 1,409.5 — 
Other non-current liabilities353.3 173.1 254.9 178.1 
Statement of Operations
Crude oil, natural gas and NGLs sales$1,440.4 $264.0 $968.8 $183.7 
Commodity price risk management gain (loss), net(707.2)— 180.3 — 
Total revenues735.5 265.8 1,151.5 182.5 
Production costs239.0 66.4 227.0 71.6 
Gross profit1,201.4 197.6 741.8 112.1 
Impairment of properties and equipment0.3 — 2.0 880.4 
Net income (loss)(78.6)128.2 (49.2)(670.0)

Off-Balance Sheet Arrangements


At September 30, 2017,2021, we had no off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital investments or capital resources.


TableContractual Obligations

Since December 31, 2020, other than the Fifth Amended and Restated Credit Agreement entered into in November 2021, there have not been any significant, non-routine changes in our contractual obligations. For details of contents


Commitments and Contingencies

See the footnote titled our contractual obligations, see Note 12 - Commitments and Contingencies, to the accompanying condensed consolidated financial statements included elsewhere in this report.Item 8. Financial Statements and Supplementary Data, of our 2020 Form 10-K.


Recent Accounting Standards


See the footnote titled SummaryThere were no significant new accounting standards adopted or new accounting pronouncements that would have potential effect on us as of Significant Accounting Policies to the accompanying condensed consolidated financial statements included elsewhere in this report.September 30, 2021.

Recent Regulatory Developments

On May 2, 2017, in response to an incident in Firestone, Colorado, the Colorado Oil & Gas Conservation Commission (“COGCC”) issued a Notice to Operators (the “Notice”). Among other things, the Notice included requirements for all operators of oil and gas wells in Colorado to inspect all existing flowlines and pipelines located within 1,000 feet of a building unit; inspect any abandoned flowlines or pipelines, regardless of distance to ensure proper abandonment; and test integrity of all connected flowlines.

We timely complied with both phases of the Notice. We have an existing Flowline Integrity Management Program to inspect all Denver-Julesburg Basin wells and related pipelines on an annual basis, and will continue to engage in this process.

On August 22, 2017, the State announced its response to the incident, following a three month review of oil and gas operations. The policy initiatives proposed could come either through rulemaking or legislation.


Critical Accounting Policies and Estimates


The preparation of the accompanying condensed consolidated financial statements in conformity with U.S. GAAP required management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenue and expenses.


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There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the condensed consolidated financial statements and accompanying notes contained in our 20162020 Form 10-K filed with the SEC on February 28, 2017.25, 2021.


Reconciliation of Non-U.S. GAAP Financial Measures

We use "adjusted“adjusted cash flows from operations," "adjustedoperations”, “adjusted free cash flow (deficit)”, “adjusted net income (loss)"” and "adjusted EBITDAX,"“adjusted EBITDAX”, non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. Beginning in 2017,In addition, we have included non-cash stock-based compensationbelieve these are measures of our fundamental business and exploration, geologic and geophysical expense in our reconciliation of adjusted EBITDAX calculation.  In prior periods, we included adjusted EBITDA, a non-U.S. GAAP financial measure that did not include these adjustments.  We have electedcan be useful to disclose Adjusted EBITDAX rather than Adjusted EBITDA in this reportus, investors, lenders, and other public disclosures because we believe it is more comparable to similar metrics presented by othersparties in the industry. All prior periods have been conformed for comparabilityevaluation of this information.our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental 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 we use may not be comparable to similarly titled measures reported by other companies. Also, inIn the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.


Adjusted cash flows from operations. operations and adjusted free cash flow (deficit). We definebelieve adjusted cash flows from operations ascan provide additional transparency into the drivers of trends in our operating cash flows, earned or incurred fromsuch as production, realized sales prices and operating activities, without regard to changes incosts, as it disregards the timing of settlement of operating assets and liabilities. We believe itadjusted free cash flow (deficit) provides additional information that may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base to fund exploration and development activities and to return capital to stockholders in the period in which the related transactions occurred. We exclude from this measure cash receipts and expenditures related to acquisitions and divestitures of oil and gas properties and capital expenditures for other properties and equipment, which are not reflective of the cash generated or used by ongoing activities on our existing producing properties and, in the case of acquisitions and divestitures, may be evaluated separately in terms of their impact on our performance and liquidity. Adjusted free cash flow is important to consider adjusteda supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations as well asbecause it excludes certain required cash flowsexpenditures. For example, we may have mandatory debt service requirements or other non-discretionary expenditures which are not deducted from operations, as wethe adjusted free cash flow measure.

We are unable to present a reconciliation of forward-looking adjusted cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe it oftenthat forward-looking estimates of adjusted cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations.

Adjusted net income (loss). We believe that adjusted net income (loss) provides moreadditional transparency into what drives the changes in our operating trends, such as production, realized sales prices, operating costs and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We
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also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has generally been a timing issue from one period to the next as we have not had significant accounts receivable collection problems, nor been unable to purchase assets or pay our obligations.

Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives, and net settlements on commodity derivatives, each adjusted for tax effect. We believederivative contracts, because it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives, and related factors, without regard todisregards changes in our net income (loss) from our mark-to-market adjustments resulting from net changes in the fair value of our unsettled derivatives. Additionally, other items whichcommodity derivative contracts, and these changes are not indicativedirectly reflective of future results may be excluded to clearly identifyour operating trends.performance.


Adjusted EBITDAX. We definebelieve that adjusted EBITDAX as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of properties and equipment, exploration, geologic, and geophysical expense, depreciation, depletion and amortization expense, accretion of asset retirement obligations, and non-cash stock-based compensation, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDAX is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), and should not be considered an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDAX includes certain non-cash costs incurred by us and does not takeprovides additional transparency into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDAX differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDAX is relevanttrends because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts, and others to analyze such things as:

operating performance and return on capital as compared to our peers;
reflects the financial performance of our assets and our valuation without regard to financing methods, capital structure, accounting methods or historical cost basis;
basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development, and acquisitions and to service our debt obligations; andobligations.
the viability of acquisition opportunities and capital expenditure projects, including the related rate of return.



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The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure:

Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
(in millions)
Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow:
Net cash from operating activities$450.4 $280.1 $1,027.8 $649.3 
Changes in assets and liabilities(33.9)(18.7)31.7 3.5 
Adjusted cash flows from operations416.5 261.4 1,059.5 652.8 
Capital expenditures for development of crude oil and natural gas properties(188.5)(57.6)(428.8)(445.5)
Change in accounts payable related to capital expenditures for oil and gas development activities40.1 24.2 (21.2)31.4 
Adjusted free cash flow$268.1 $228.0 $609.5 $238.7 
Net income (loss) to adjusted net income (loss):
Net income (loss)$145.3 $(30.8)$49.2 $(717.6)
Loss (gain) on commodity derivative instruments217.7 68.1 707.2 (245.9)
Net settlements on commodity derivative instruments(129.6)66.9 (215.4)227.5 
Tax effect of above adjustments (1)
— — — — 
Adjusted net income (loss)$233.4 $104.2 $541.0 $(736.0)
Net income (loss) to adjusted EBITDAX:
Net income (loss)$145.3 $(30.8)$49.2 $(717.6)
Loss (gain) on commodity derivative instruments217.7 68.1 707.2 (245.9)
Net settlements on commodity derivative instruments(129.6)66.9 (215.4)227.5 
Non-cash stock-based compensation5.8 5.4 17.3 17.4 
Interest expense, net20.1 21.0 59.2 67.0 
Income tax expense (benefit)0.2 0.2 0.1 (3.5)
Impairment of properties and equipment0.1 1.2 0.3 882.3 
Exploration, geologic and geophysical expense0.2 0.2 0.9 1.0 
Depreciation, depletion and amortization169.6 144.5 478.6 470.2 
Accretion of asset retirement obligations2.8 2.4 9.2 7.4 
Loss (gain) on sale of properties and equipment(0.2)(0.3)(0.6)(0.6)
Adjusted EBITDAX$432.0 $278.8 $1,106.0 $705.2 
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities$450.4 $280.1 $1,027.8 $649.3 
Interest expense, net20.1 21.0 59.2 67.0 
Amortization and write-off of debt discount, premium and issuance costs(3.5)(3.6)(11.2)(12.5)
Exploration, geologic and geophysical expense0.2 0.2 0.9 1.0 
Other(1.2)(0.2)(2.4)(3.1)
Changes in assets and liabilities(34.0)(18.7)31.7 3.5 
Adjusted EBITDAX$432.0 $278.8 $1,106.0 $705.2 
_____________
(1)Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the three and nine months ended September 30, 2021 and 2020.

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 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Adjusted cash flows from operations:       
Net cash from operating activities$148.2
 $163.0
 411.4
 $360.8
Changes in assets and liabilities2.7
 (40.4) (3.9) (34.6)
Adjusted cash flows from operations$150.9
 $122.6
 $407.5
 $326.2
        
Adjusted net loss:       
Net loss$(292.5) $(23.3) $(205.1) $(190.3)
(Gain) loss on commodity derivative instruments52.2
 (19.4) (86.5) 62.3
Net settlements on commodity derivative instruments9.6
 47.7
 22.2
 167.9
Tax effect of above adjustments(23.2) (10.8) 24.0
 (87.6)
Adjusted net loss$(253.9) $(5.8) $(245.4) $(47.7)
        
Net loss to adjusted EBITDAX:       
Net loss$(292.5) $(23.3) $(205.1) $(190.3)
(Gain) loss on commodity derivative instruments52.2
 (19.4) (86.5) 62.3
Net settlements on commodity derivative instruments9.6
 47.7
 22.2
 167.9
Non-cash stock-based compensation4.8
 4.1
 14.6
 15.2
Interest expense, net18.8
 20.1
 56.9
 40.9
Income tax benefit(122.4) (12.0) (71.5) (112.2)
Impairment of properties and equipment252.7
 0.9
 282.5
 6.1
Impairment of goodwill75.1
 —
 75.1
 —
Exploration, geologic, and geophysical expense41.9
 0.2
 43.9
 0.7
Depreciation, depletion, and amortization125.2
 112.9
 360.6
 317.3
Accretion of asset retirement obligations1.5
 1.8
 4.9
 5.4
Adjusted EBITDAX$166.9
 $133.0
 $497.6
 $313.3
        
Cash from operating activities to adjusted EBITDAX:       
Net cash from operating activities$148.2
 $163.0
 $411.4
 $360.8
Interest expense, net18.8
 20.1
 56.9
 40.9
Amortization of debt discount and issuance costs(3.2) (9.9) (9.6) (13.0)
Gain on sale of properties and equipment0.1
 0.2
 0.8
 —
Exploration, geologic, and geophysical expense41.9
 0.2
 43.9
 0.7
Exploratory dry hole costs(41.2) —
 (41.2) —
Other(0.4) (0.2) 39.3
 (41.5)
Changes in assets and liabilities2.7
 (40.4) (3.9) (34.6)
Adjusted EBITDAX$166.9
 $133.0
 $497.6
 $313.3


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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


Market-Sensitive Instruments and Risk Management


We are exposed to market risks associated with interest rate risks,rates, commodity price risk and credit risk.risks. We have established risk management processes to monitor and manage these market risks.


Interest Rate Risk


Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 2021 Convertible Notes, 2024 Senior Notes, and 2022 Senior Notes have fixed rates, and therefore near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.


As of September 30, 2017, our interest-bearing deposit accounts included money market accounts, certificates of deposit, and checking and savings accounts with various banks. The amount of our interest-bearing cash, cash equivalents, and restricted cash as of September 30, 2017 was $105.6 million with a weighted-average interest rate of 1.0 percent. Based on a sensitivity analysis of our interest-bearing deposits as of September 30, 2017 and assuming we had $105.6 million outstanding throughout the period, we estimate that a one percent increase in interest rates would have increased interest income for the nine months ended September 30, 2017 by approximately $0.8 million.

As of September 30, 2017,2021, we had no outstanding balance on our revolving credit facility.
    
Commodity Price Risk


We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, natural gas basis and NGLs. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas and propane prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives.

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The following table presents our commodity and basis derivative positions related to crude oil, natural gas, and propane in effect as of September 30, 2017:
  Collars Fixed-Price Swaps  
Commodity/ Index/
Maturity Period
 
Quantity
(Gas -
BBtu
Oil - MBbls)
 
Weighted-Average
Contract Price
 
Quantity (Oil - MBbls
Gas and Basis-
BBtu
 Propane - MBbls)
 
Weighted-
Average
Contract
Price
 
Fair Value
September 30,
2017 (1)
(in millions)
  Floors Ceilings   
Crude Oil            
NYMEX            
2017 616.0
 $49.54
 $62.32
 1,837.1
 $50.13
 $(2.6)
2018 1,512.0
 41.85
 54.31
 7,972.0
 52.11
 (0.6)
2019 —
 —
 —
 2,400.0
 50.25
 (1.8)
Total Crude Oil 2,128.0
     12,209.1
   $(5.0)
             
Natural Gas            
NYMEX            
2017 2,895.1
 $3.38
 $4.02
 10,310.0
 $3.39
 $4.6
2018 5,230.0
 3.00
 3.54
 51,280.0
 2.95
 (4.1)
Total Natural Gas 8,125.1
     61,590.0
   $0.5
             
Basis Protection            
CIG            
2017 —
 —
 —
 13,264.2
 $(0.34) $0.6
2018 —
 —
 —
 30,200.0
 (0.34) 3.7
Waha            
2018 —
 —
 —
 6,000.0
 (0.50) 0.1
Total Basis Protection —
     49,464.2
   $4.4
             
Propane            
Mont Belvieu            
2017 —
 —
 —
 411.9
 $27.22
 $(4.3)
2018 —
 —
 —
 428.6
 29.14
 (1.3)
Total Propane       840.5
   $(5.6)
Commodity Derivatives Fair Value       $(5.7)
             
____________

(1)Approximately 10.8 percent of the fair value of our commodity derivative assets and 28.4 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).

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In addition to our commodity derivative positions as of September 30, 2017, we entered into the following commodity derivative positions subsequent to September 30, 2017 that are effective as of November 3, 2017:

  Fixed-Price Swaps
Commodity/ Index/
Maturity Period
 
Quantity (Oil - MBbls
Gas and Basis-
BBtu
 Propane - MBbls)
 
Weighted-
Average
Contract
Price
  
Crude Oil    
NYMEX    
2018 600.0
 $53.30
2019 600.0
 $51.43
     
Total Crude Oil 1,200.0
  
     
Basis Protection    
CIG    
2018 5,000.0
 $(0.51)
     
El Paso    
2018 3,000.0
 $(0.62)
     
Total Basis Swaps 8,000.0
  
     
Rollfactor (1)    
2018 3,648.0
 $0.03

(1)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 (the "trade month roll").

Our realized prices vary regionally based on local market differentials and our transportation agreements. The following table presents average market index prices for crude oil and natural gas for the periods identified, as well as the average sales prices we realized for our crude oil, natural gas, and NGLs production:

 Three Months Ended Nine Months Ended Year Ended
 September 30, 2017 September 30, 2017 December 31, 2016
Average NYMEX Index Price:     
Crude oil (per Bbl)$48.20
 $49.47
 $43.32
Natural gas (per MMBtu)3.00
 3.17
 2.46
      
Average Sales Price Realized:     
Excluding net settlements on commodity derivatives    
Crude oil (per Bbl)$45.66
 $46.69
 $39.96
Natural gas (per Mcf)2.17
 2.23
 1.77
NGLs (per Bbl)18.11
 17.24
 11.80


Based on a sensitivity analysis as of September 30, 2017,2021, we estimate that a ten percent increase in natural gas, crude oil prices and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives
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in place, would have resulted in a decreasean increase in the fair value of our net derivative positionsliabilities of $83.9$131.7 million, whereas a ten percent decrease in prices would have resulted in an increasea decrease in fair value of $83.7our net derivative liabilities of $130.3 million. The potential increase in the fair value of our net derivative liabilities would be recorded in statements of operations as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.


Credit Risk


Credit risk represents the loss that we would incur if a counterparty fails to perform its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties.exposure. When exposed to significant credit risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties.

Our oil and gas exploration and production business's crude oil, natural gas, and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers.

Amounts due to our gas marketing business are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions, and end-users in various industries. The underlying operations of these entities are geographically concentrated in the same region, which increases the credit risk associated with this business. As natural gas prices continue to remain depressed, certain third-party producers relating to our gas marketing business continue to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, we have had no material counterparty default losses. We have initiated several legal actions for breach of contract, collection and related claims against certain third-party producers that are delinquent in their payment obligations, which have to date resulted in two default judgments. We expect this trend to continue for this business.


We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments. See

Our crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. We do not require our customers to post collateral, and the footnote titled Commodity Derivative Financial Instrumentsinability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our condensed consolidated financial statements included elsewhere in this report for more detail on our commodity derivative financial instruments.results.


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Disclosure of Limitations


Because the information above included only those exposures that existed at September 30, 2017,2021, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time.


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ITEM 4. CONTROLS AND PROCEDURES


Evaluation of Disclosure Controls and Procedures


As of September 30, 2017,2021, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Actdefined in Rules 13a-15(e) and 15d-15(e).

of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2017.2021.

Changes in Internal Control over Financial Reporting


During the three months ended September 30, 2017, we madeThere were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) ofduring the Exchange Act)quarter ended September 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II
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PART II
ITEM 1. LEGAL PROCEEDINGS


From time to time, we are a party to variousInformation regarding our legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations, or liquidity.

Environmental

Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any environmental claims existing as of September 30, 2017 which have not been provided for or would otherwise have a material impact onfound in Note 11 - Commitments and Contingencies to our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown past non-compliance with environmental laws will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets.financial statements included elsewhere in this report.


Clean Air Act Tentative Agreement and Related Consent Decree

In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the U.S. Environmental Protection Agency ("EPA"). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado ("DJ Basin"). The Information Request focused on historical operation and design information for 46 of our production facilities and requested sampling and analyses at the identified 46 facilities. We responded to the Information Request with the requested data in January 2016.
In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. 25-7-115(2) from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law.

For more than a year, we held a series of meetings with the EPA, Department of Justice (“DOJ”) and CDPHE on the above matters. On June 26, 2017, the DOJ on behalf of the EPA and the State of Colorado filed a complaint against us based on the above matters. We continued to conduct meetings with these agencies in working toward a resolution of the matters. On September 28, 2017, the parties jointly filed for an extension of time for PDC to reply to the complaint. The extension was requested because the parties reached an agreement to resolve the case subject to final approval by the appropriate persons within the federal government and state government, as well as outcome of the period of public comment on the proposed decree.

A consent decree was signed by all parties on October 31, 2017 and is subject to a 30-day comment period in which it will be publicly published in the Federal Register. The consent decree provides that we will implement changes to our design, operation, and maintenance of most of our field-wide storage tank systems to enhance our emission management in the DJ Basin.  Agreed upon and planned efforts include, but are not limited to, vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. We voluntarily included in the consent decree approximately 40 additional facilities associated with our pending acquisition of additional assets in the basin.  The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1 million in supplemental environmental projects); (ii) injunctive relief with an estimated cost of approximately $18 million, primarily representing capital enhancements to our operations; and (iii) mitigation with an estimated cost of $1.7 million.  Certain expenditures for the injunctive relief are believed to have been incurred in 2016 and 2017, with the remainder expected to be incurred over the next few years. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. Although we believe the consent decree will be approved by the court following the comment period, this cannot be guaranteed. 

Action Regarding Firm Transportation Contracts
In June 2016, a group of 42 independent West Virginia natural gas producers filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. ("Dominion"), certain entities affiliated with Dominion, and our
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subsidiary RNG as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. The case has been transferred to the Business Court Division of the Circuit Court of Marshall County, West Virginia, and the parties are awaiting that court's ruling on previously-filed pre-trial pleadings. RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defenses.


ITEM 1A. RISK FACTORS


We face many risks. Factors thatrisks. Each of these risk factors could materially adversely affect our business, operating results, and financial condition operating results, or liquidity andas well as the trading pricevalue of an investment in our common stock are described under Item 1A, Risk Factors, of our 20162020 Form 10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.


There have been no material changes from the risk factors previously disclosed in our 20162020 Form 10-K.


ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
        
The following table presents information about our purchases of our common stock during the three months ended September 30, 2021:
Period
Total Number of Shares Purchased (1) (2)
Average Price Paid per Share
Total Number
of Shares Purchased as Part of Publicly Announced Plans or Programs (1)
Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs
(in millions)
July283,191 $41.10 280,000 $286.7 
August915,811 39.30 915,000 250.7 
September281,058 43.47 281,058 238.5 
Total third quarter 2021 purchases1,480,060 40.43 1,476,058 238.5 
_____________
(1)In April 2019, our board of directors approved a program to acquire up to $200 million of our outstanding common stock and in August 2019, effective with the closing of the SRC Acquisition, increased such amount to $525 million (the “Stock Repurchase Program”). The Stock Repurchase Program does not require any specific number of shares to be acquired and can be modified or discontinued by our board of directors at any time. We reinstated our Stock Repurchase Program in late February 2021. Repurchases may extend until December 31, 2023.
(2)Purchases outside of Equity Securities by the Issuer and Affiliated PurchasersStock Repurchase Program represent shares withheld from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. The withheld shares are not considered common stock repurchased under the Stock Repurchase Program.


Period Total Number of Shares Purchased (1) Average Price Paid per Share
     
July 1 - 31, 2017 1,360
 $42.68
August 1 - 31, 2017 —
 —
September 1 - 30, 2017 12
 39.58
Total third quarter 2017 purchases 1,372
 $42.65
     
__________
(1)Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES - None.


ITEM 4. MINE SAFETY DISCLOSURES - Not applicable.


ITEM 5. OTHER INFORMATION

On November 2, 2021, we entered into a New Credit Facility agreement. Information regarding the New Credit Facility can be found in Note 8 - None.Long Term Debt to our condensed consolidated financial statements included elsewhere in this report.


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PDC ENERGY, INC.

ITEM 6. EXHIBITS

Incorporated by Reference
Exhibit NumberExhibit DescriptionFormSEC File NumberExhibitFiling DateFiled Herewith
Incorporated by Reference
Exhibit Number10.1Exhibit DescriptionFormSEC File NumberExhibitFiling DateFiled Herewith
10.1

X
31.122X
31.1X
31.2
Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
X
32.1*
101.INSXBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL documentX
101.SCHXBRL Taxonomy Extension Schema DocumentX
101.CALXBRL Taxonomy Extension Calculation Linkbase DocumentX
101.DEFXBRL Taxonomy Extension Definition Linkbase DocumentX
101.LABXBRL Taxonomy Extension Label Linkbase DocumentX
101.PREXBRL Taxonomy Extension Presentation Linkbase DocumentX
* Furnished herewith.104Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)X
* Furnished herewith.
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PDC ENERGY, INC.

SIGNATURES


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, thereunto duly authorized.

PDC Energy, Inc.
(Registrant)
PDC Energy, Inc.
(Registrant)
Date: November 6, 20173, 2021/s/ Barton R. Brookman
Barton R. Brookman
President and Chief Executive Officer
(principal executive officer)
/s/ David W. HoneyfieldR. Scott Meyers
David W. HoneyfieldR. Scott Meyers
Senior Vice President and Chief Financial Officer
(principal financial officer)

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