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•	target specific regions where we either have, or believe we can create, a competitive advantage as a result of our ownership or use of CO2 reserves, oil fields and CO2 infrastructure;

•	secure properties where we believe additional value can be created through tertiary recovery operations and a combination of other exploitation, development, exploration and marketing techniques;

•	acquire properties that give us a majority working interest and operational control or where we believe we can ultimately obtain it;

•	maximize the value and cash flow generated from our operations by increasing production and reserves while controlling costs;

•	optimize the timing and allocation of capital among our investment opportunities to maximize the rates of return on our investments;

•	exercise financial discipline by attempting to balance our development capital expenditures with our cash flows from operations; and

•	attract and maintain a highly competitive team of experienced and incentivized personnel.

•	Generated $494.1 million of cash flow from operations ($408.8 million after reducing for interest payments treated as debt reduction), significantly exceeding our $273.6 million of incurred development capital expenditures and capitalized interest in 2019.

•	Reduced our debt principal by $250.5 million and significantly improved our debt maturity profile, ending the year with no outstanding borrowings on the Company’s senior secured bank credit facility.

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•	Continued progress on the CO2 enhanced oil recovery development project at Cedar Creek Anticline (“CCA”), Denbury’s largest oil field, to access the potential for significant long-term oil production and cash flow from this key asset, with project activities and capital primarily related to procurement of the pipe and preparation for installation of the CO2 pipeline to CCA.

•	Improved our leverage ratio to 3.7x during 2019 from 4.2x during 2018 (ratio of net debt (debt principal less cash) to Adjusted EBITDAX (a non-GAAP measure)) (see Non-GAAP Financial Measures and Reconciliations).

•	Reduced general and administrative expenses (excluding $18.6 million of severance expense related to a voluntary separation program) by $7.1 million, a 10% reduction from 2018 amounts.

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Continued to optimize our oil and natural gas asset portfolio through the following: (1) sold Citronelle Field for approximately $10 million in July 2019 and (2) entered into an agreement in December 2019 to sell half of our nearly 100% working interests in four conventional southeast Texas oil fields for $50 million and a carried interest in ten wells to be funded and drilled by the purchaser, which is currently expected to occur in March 2020 (the “Pending Gulf Coast Working Interests Sale”).

•

Continued the monetization of valuable surface land with no active oil and natural gas operations around Houston, Texas, including (1) the sale of multiple parcels primarily around Houston, Texas in transactions totaling $14 million in 2019 and (2) entered into a contract to sell acreage around Houston, Texas for $32 million which provides for a substantial portion of the cash proceeds from such sale to be received no later than mid-2021 with the remaining portion of cash proceeds to be received by mid-2022, subject to certain conditions. We are actively working with the buyer to potentially close the first portion of this sale before the end of 2020.

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(1)

The reference prices were based on the arithmetic average of the first-day-of-the-month NYMEX commodity prices for each month during the respective year. These prices do not reflect adjustments for market differentials by field that are utilized in the preparation of our reserve report to arrive at the appropriate net price we receive. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Operating Results Table for details of oil and natural gas prices received, both including and excluding the impact of derivative settlements.

(2)

Determined based on the average first-day-of-the-month prices for each month, adjusted to prices received by field in accordance with standards set forth in the Financial Accounting Standards Board Codification (“FASC”). PV-10 Values and the Standardized Measure are significantly impacted by the oil prices we receive relative to NYMEX oil prices (our NYMEX oil price differential). The weighted-average oil price differentials utilized were $0.14 per Bbl below representative NYMEX oil prices as of December 31, 2019, compared to $0.24 per Bbl below NYMEX oil prices as of December 31, 2018, and $2.25 per Bbl below NYMEX oil prices as of December 31, 2017.

(3)	PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. See Non-GAAP Financial Measures and Reconciliations for further discussion.

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(1)	Reserve estimates were prepared in accordance with FASC Topic 932, Extractive Industries – Oil and Gas, using the arithmetic averages of the first-day-of-the-month NYMEX commodity price for each month during 2019, which were $55.69 per Bbl for crude oil and $2.58 per MMBtu for natural gas.

(2)	Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields in Mississippi.

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(3)	Texas non-tertiary production includes production associated with the Pending Gulf Coast Working Interests Sale (see Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Pending Sale of Working Interests in Certain Texas Fields).

(4)	The Cedar Creek Anticline consists of a series of 13 different operating areas.

(5)	Includes production from Citronelle Field sold in July 2019.

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(1)

An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.  A development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(2)	A productive well is an exploratory or development well drilled and completed during the year and found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

(3)	A non-productive well is an exploratory or development well that is not a productive well.

(4)	During 2019, 2018 and 2017, an additional 7, 4 and 3 wells, respectively, were drilled for water or CO2 injection purposes.

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(1)	Excludes oil and natural gas ad valorem and production taxes.

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•	the level of worldwide consumer demand for oil and natural gas, which has recently been negatively affected by concerns about the impact of the COVID-19 coronavirus, and the domestic and foreign supply of oil and natural gas and levels of domestic oil and natural gas storage;

•	the degree to which members of the Organization of Petroleum Exporting Countries maintain oil price and production controls;

•	the degree to which domestic oil and natural gas production affects worldwide supply of crude oil or its price;

•	worldwide political events, conditions and policies, including actions taken by foreign oil and natural gas producing nations; and

•	worldwide economic conditions.

•	lower cash flows from operations may require reduced levels of capital expenditures;

•	reduced levels of capital expenditures in turn could lower our present and future production levels, and lower the quantities and value of our oil and gas reserves, which constitute our major asset;

•	our lenders could reduce our borrowing base, and we may not be able to raise capital at attractive rates in the public markets;

•	we could have difficulty repaying or refinancing our indebtedness;

•	we could be forced to increase our level of indebtedness, issue additional equity, or sell assets;

•	we could be required to impair various assets, including a write-down of our oil and natural gas assets or the value of other tangible or intangible assets; and/or

•	our potential cash flows from our commodity derivative contracts that include sold puts could be limited to the extent that oil prices are below the prices of those sold puts.

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•	To February 12, 2021, if on that date the sum of the Company’s cash, cash equivalents and borrowing availability under the senior secured bank credit facility is less than 120% of the amount of the then outstanding 2021 Senior Secured Notes;

•	To May 14, 2021, if either (a) prior to that date the 2021 Senior Secured Notes have not been repaid or otherwise redeemed in full, or (b) on that date the sum of the Company’s cash, cash equivalents and borrowing availability under the senior secured bank credit facility is less than 120% of the amount of the then outstanding 2021 Senior Subordinated Notes; or

•	To August 13, 2021, if prior to that date the 2021 Senior Subordinated Notes have not been repaid or otherwise redeemed in full.

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•	unexpected drilling conditions;

•	pressure or irregularities in formations;

•	equipment failures or accidents;

•	adverse weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico that can damage oil and natural gas facilities and delivery systems and disrupt operations, and winter conditions and forest fires in the Rocky Mountain region that can delay or impede operations;

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•	compliance with environmental and other governmental requirements;

•	the cost of, or shortages or delays in the availability of, drilling rigs, equipment, pipelines and services; and

•	title problems.

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(1)	Shares purchased during the fourth quarter of 2019 were made in connection with the surrender of shares by our employees to satisfy their tax withholding requirements related to the vesting of restricted shares.

(2)

In October 2011, we commenced a common share repurchase program, which has been approved for up to an aggregate of $1.162 billion of Denbury common shares by the Company’s Board of Directors. This program has effectively been suspended and we do not anticipate repurchasing shares of our common stock in the near future. The program has no pre-established ending date and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.

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(1)	Includes pre-tax impairments of assets of $810.9 million and $6.2 billion for the years ended December 31, 2016 and 2015, respectively, and an accelerated depreciation charge of $591.0 million related to the Riley Ridge gas processing facility and related assets for the year ended December 31, 2016.

(2)	In September 2015, in light of the low oil price environment and our desire to maintain our financial strength and flexibility, the Company’s Board of Directors suspended our quarterly cash dividend.

(3)	Reflects the adoption of Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (“ASU 2016-18”), whereby changes in restricted cash are now included in the consolidated statements of cash flows. We adopted ASU 2016-18 effective January 1, 2018, which was applied retrospectively to all periods presented.

(4)

Lease operating expenses reported in this table for 2015 include certain special items comprised of (1) lease operating expenses and related insurance recoveries recorded to remediate an area of Delhi Field, (2) a reimbursement for a retroactive utility rate adjustment, and (3) other insurance recoveries. If these special items are excluded, lease operating expenses would have totaled $528.8 million, or $19.88 per BOE, for the year ended December 31, 2015.

(5)	Depletion, depreciation, and amortization during the year ended December 31, 2016 includes an accelerated depreciation charge of $591.0 million, or $25.23 per BOE, associated with the Riley Ridge gas processing facility and related assets.

(6)

Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross or 8/8ths working interest basis, of which our net revenue interest was approximately 3.8 Tcf, 4.0 Tcf, 4.1 Tcf, 4.2 Tcf and 4.4 Tcf at December 31, 2019, 2018, 2017, 2016 and 2015, respectively, and include reserves dedicated to volumetric production payments of 3.1 Bcf, 7.6 Bcf, 12.3 Bcf and 25.3 Bcf at December 31, 2018, 2017, 2016 and 2015, respectively (see Supplemental CO2 Disclosures (Unaudited) to the Consolidated Financial Statements).

(7)	Proved CO2 reserves in the Rocky Mountain region consist of our overriding royalty interest in LaBarge Field, of which our net revenue interest was approximately 1.1 Tcf, 1.2 Tcf, 1.2 Tcf, 1.2 Tcf and 1.2 Tcf at December 31, 2019, 2018, 2017, 2016 and 2015, respectively (see Supplemental CO2 Disclosures (Unaudited) to the Consolidated Financial Statements).

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•	Oil and natural gas revenues decreased by $210.6 million (15%), with 11% of the decrease due to lower commodity prices and 4% of the decrease due to lower production, offset in part by an improvement in derivative commodity settlements of $198.8 million from the prior year;

•	Commodity derivative expense increased by $91.2 million, resulting from a $198.8 million improvement in cash settlements ($175.2 million of cash payments in 2018 compared to $23.6 million of cash receipts in 2019) which was more than offset by $290.0 million of expense for noncash fair value changes in commodity derivatives between 2018 and 2019;

•	A noncash gain on debt extinguishment of $156.0 million in 2019 (see 2019 Debt Reduction Transactions below);

•	$18.6 million of severance expense in 2019 associated with our voluntary separation program (see December 2019 Voluntary Separation Program below);

•	A $73.1 million reduction in other expense, as 2018 included $49.4 million of litigation expense and a $17.8 million asset impairment; and

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Our diluted per share net income in 2019 was affected by the inclusion of an additional 90.9 million shares of the Company’s common stock issuable upon conversion of our convertible senior notes which were issued in June 2019, increasing our diluted share count by those shares for the portion of the year the notes were outstanding (see Note 1, Nature of Operations and Summary of Significant Accounting Policies – Net Income per Common Share, to the Consolidated Financial Statements).

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•	During June 2019, through a series of debt exchanges, we extended the maturities of $348.4 million of our outstanding long-term debt to 2024 and reduced our debt principal by $120.0 million, with holders exchanging $468.4 million aggregate principal amount of our subordinated notes for:

–	$245.5 million aggregate principal amount of our new 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”);

–	$102.6 million aggregate principal amount of new 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”); and

–	$120.0 million of cash.

•

During June and July 2019, as part of creating a more liquid series of secured second lien debt due in 2024, we also exchanged $429.2 million aggregate principal amount of 7¾% Senior Secured Notes for $429.4 million of previously outstanding 7½% Senior Secured Second Lien Notes due 2024. As a result of all of the above June and July note exchanges, we recognized a gain on debt extinguishment, net of transaction costs, totaling $100.5 million for the year ended December 31, 2019, in our Consolidated Statements of Operations.

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Between August and November 2019, we repurchased $112.1 million (approximately 31%) of our $357.8 million aggregate principal amount of senior subordinated notes outstanding as of June 30, 2019 for $16.4 million of cash and issuance of 38.3 million shares of the Company’s common stock. In connection with these transactions, we recognized a $55.5 million gain on debt extinguishment, net of unamortized debt issuance costs written off, during the year ended December 31, 2019, in our Consolidated Statements of Operations.

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•	A Consolidated Total Debt to Consolidated EBITDAX financial maintenance covenant, with such ratio not to exceed 5.25 to 1.0 through December 31, 2020 and 4.50 to 1.0 thereafter;

•	A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 2.5 to 1.0. Only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;

•	A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and

•	A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0 to 1.0.

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•	$75 million allocated for tertiary oil field expenditures;

•	$55 million allocated for other areas, primarily non-tertiary oil field expenditures including exploitation;

•	$10 million to be spent on CO2 sources and pipelines; and

•	$40 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

(1)	Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

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(1)

Represents future cash commitments under contracts in place as of December 31, 2019, primarily for purchase contracts for CO2 captured from industrial sources, transportation agreements and well-related costs, but excludes any potential payments related to the APMTG litigation being appealed.  As is common in our industry, we commit to make certain expenditures on a regular basis as part of our ongoing development and exploration program.  These commitments generally relate to projects that occur during the subsequent several months and are usually part of our normal operating expenses or part of our capital budget (see 2020 Capital Budget Allocation and Estimated Cash Flows above).  We also have recurring expenditures for such things as accounting, engineering and legal fees; software maintenance; subscriptions; and other overhead-type items.  Normally these expenditures do not change materially on an aggregate basis from year to year and are part of our general and administrative expenses.  We have not attempted to estimate the amounts of these types of recurring expenditures in this table, as most could be quickly canceled with regard to any specific vendor, even though the expense itself may be required for our ongoing normal operations. For further discussion of our long-term commitments to purchase CO2 and any payments related to the APMTG litigation being appealed, see Note 12, Commitments and Contingencies, to the Consolidated Financial Statements.

(2)

Commodity derivative liabilities represent the fair value of our commodity derivatives presented as liabilities in our Consolidated Balance Sheets as of December 31, 2019. The ultimate settlement amounts of our derivative obligations are unknown because they are subject to continuing market fluctuations. See further discussion of our commodity derivative contracts and their market price sensitivities in Market Risk Management below in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, and in Note 10, Commodity Derivative Contracts, to the Consolidated Financial Statements.

(3)

Represents the estimated future asset retirement obligations on an undiscounted basis.  The present value of the discounted asset retirement obligation is $181.8 million, as determined under the Asset Retirement and Environmental Obligations topic of the Financial Accounting Standards Board Codification (“FASC”), and is further discussed in Note 4, Asset Retirement Obligations, to the Consolidated Financial Statements.

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(1)	See also Commodity Derivative Contracts below and Market Risk Management for information concerning our commodity derivative transactions.

(2)	Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Consolidated Statements of Operations in that the noncash fair value gains (losses) on commodity derivatives represent only the net changes between periods of the fair market values of commodity derivative

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(1)	Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields.

(2)	Represents production related to the acquisition of a 23% non-operated working interest in Salt Creek Field in Wyoming, which closed on June 30, 2017.

(3)	Includes non-tertiary production related to the sale of 50% of our working interests in Webster, Thompson, Manvel, and East Hastings fields, which is expected to close in March 2020 and averaged 1,170 BOE/d and 1,085 BOE/d for the three and twelve months ended December 31, 2019, respectively.

(4)	Includes production from Citronelle Field sold in July 2019 and Lockhart Crossing Field sold in the third quarter of 2018.

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•	Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a positive $3.30 per Bbl and a positive $2.94 per Bbl during 2019 and 2018, respectively. Generally, our Gulf Coast region differentials are positive to

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Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $2.01 per Bbl below NYMEX during 2019, compared to an average differential of $1.50 per Bbl below NYMEX in 2018. Differentials in the Rocky Mountain region can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility.

(1)

Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value gains (losses) on commodity derivatives to “Commodity derivatives expense (income)” in the Consolidated Statements of Operations. See also the Glossary and Selected Abbreviations for the definition of noncash fair value gains (losses) on commodity derivatives.

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(1)	Averages are volume weighted.

(2)	If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and the sold put price.

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(1)

Cash interest includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. The portion of interest treated as a reduction of debt relates to our 2021 Senior Secured Notes, 2022 Senior Secured Notes, and our previously outstanding 3½% Convertible Senior Notes due 2024 and 5% Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes”). See below for further discussion.

(2)	Represents amortization of debt discounts of $2.6 million related to the 7¾% Senior Secured Notes and $5.1 million related to the 2024 Convertible Senior Notes during the year ended December 31, 2019.

(3)	Excludes debt discounts related to our 7¾% Senior Secured Notes and 2024 Convertible Senior Notes.

(4)	Includes commitment fees but excludes debt issue costs and amortization of discount.

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(1)

General and administrative expenses includes an accrual for severance-related costs of $18.6 million associated with our voluntary separation program for the year ended December 31, 2019 and payments of $6.2 million related to an involuntary workforce reduction for the year ended December 31, 2017, which if excluded, would have averaged $3.03 per BOE and $4.35 per BOE for the years ended December 31, 2019 and 2017, respectively.

(2)

Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value gains (losses) on commodity derivatives to “Commodity derivatives expense (income)” in the Consolidated Statements of Operations. See also the Glossary and Selected Abbreviations for the definition of noncash fair value gains (losses) on commodity derivatives.

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•	assessment of impairment of long-lived assets; and

•	recorded value of commodity derivative instruments.

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Note 1. Nature of Operations and Summary of Significant Accounting Policies

Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO₂ enhanced oil recovery operations.

Principles of Reporting and Consolidation

The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of Denbury and entities in which we hold a controlling financial interest.  Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis.  All intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during each reporting period.  Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.  Significant estimates underlying these financial statements include (1) the fair value of financial derivative instruments; (2) the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test; (3) future net cash flow estimates used in the impairment assessment of long-lived assets; (4) the estimated quantities of proved and probable CO₂ reserves used to compute depletion of CO₂ properties; (5) estimated useful lives used to compute depreciation and amortization of long-lived assets; (6) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (7) the estimated costs and timing of future asset retirement obligations; and (8) estimates made in the calculation of income taxes.  While management is not aware of any significant revisions to any of its current year-end estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application.  These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs. 

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. On the Consolidated Statements of Operations for the years ended December 31, 2018 and 2017, “Purchased oil sales” is a new line item and includes sales related to purchases of oil from third-parties, which were reclassified from “Other income,” “Purchased oil expenses” is a new line item and includes expenses related to purchases of oil from third-parties, which were reclassified from “Marketing and plant operating expenses” used in prior reports, and “Transportation and marketing expenses” is a new line item, previously captioned “Marketing and plant operating expenses,” but adjusted to exclude both expenses related to plant operating expenses, which were reclassified to “Other expenses,” and also purchases of oil from third parties. Such reclassifications had no impact on our reported total revenues, expenses, net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity.

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Cash, Cash Equivalents, and Restricted Cash

We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of year” as reported within the Consolidated Statements of Cash Flows:

		December 31,
In thousands		2019				2018
Cash and cash equivalents		$	516			$	38,560
Restricted cash included in other assets		32,529				16,389
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows		$	33,045			$	54,949

Amounts included in restricted cash included in “Other assets” in the accompanying Consolidated Balance Sheets represent escrow accounts that are legally restricted for certain of our asset retirement obligations.

Oil and Natural Gas Properties

Capitalized Costs.  We follow the full cost method of accounting for oil and natural gas properties.  Under this method, all costs related to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States.  Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities.  We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the Financial Accounting Standards Board Codification (“FASC”) Fair Value Measurement topic.  Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of 25% or more of our proved reserves would be considered significant.

Depletion and Depreciation.  The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers.  Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil.

Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties.  The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. As a result of this analysis, we recognized impairments of our unevaluated costs totaling $18.2 million and $21.4 million during the years ended December 31, 2019 and 2017, respectively, whereby these costs were transferred to the full cost amortization base. We did not record any impairments of our unevaluated costs during the year ended December 31, 2018.

 

Write-Down of Oil and Natural Gas Properties.  The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling.  The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects.  Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO₂ reserves nor those related to the cost of constructing CO₂ pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves.  Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO₂ costs related to CO₂ reserves and CO₂ pipelines that we estimate will be consumed in the process of producing

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our proved oil and natural gas reserves.  The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes.  The cost center ceiling test is prepared quarterly. We did not record any ceiling test write-downs during 2017, 2018 or 2019.

Joint Interest Operations.  Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others.  These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables.

 

Tertiary Injection Costs.  Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the Securities and Exchange Commission (“SEC”) rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO₂ injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood.  

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO₂ injections (i.e., a production response).  These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field.  After we see a production response to the CO₂ injections (i.e., the production stage), injection costs are expensed as incurred, and once proved reserves are recognized, previously deferred unevaluated development costs become subject to depletion.

CO₂ Properties

We own and produce CO₂ reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users.  We record revenue from our sales of CO₂ to third parties when it is produced and sold.  Expenses related to the production of CO₂ are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production.  The expenses related to third-party sales are recorded in “CO₂ discovery and operating expenses,” and the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations or are capitalized as oil and natural gas properties in our Consolidated Balance Sheets, depending on the stage of the tertiary flood that is receiving the CO₂ (see Tertiary Injection Costs above for further discussion).

Costs incurred to search for CO₂ are expensed as incurred until proved or probable reserves are established.  Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO₂ properties” on our Consolidated Balance Sheets.  Capitalized CO₂ costs are aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves.

Pipelines and Plants

CO₂ used in our tertiary floods is transported to our fields through CO₂ pipelines.  Costs of CO₂ pipelines under construction are not depreciated until the pipelines are placed into service.  Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 20 to 50 years. Capitalized costs include $117.6 million of CO₂ pipelines as of December 31, 2019, that were either under construction or had not been placed into service and therefore, were not subject to depreciation during 2019.

Property and Equipment – Other

Other property and equipment, which includes furniture and fixtures, vehicles, and computer equipment and software, is depreciated principally on a straight-line basis over each asset’s estimated useful life.  Vehicles and furniture and fixtures are generally depreciated over a useful life of five to ten years, and computer equipment and software are generally depreciated over a useful life of three to five years.  Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term.

Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred.

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Intangible Assets

Our intangible assets subject to amortization primarily consist of amounts assigned in purchase accounting to a CO₂ purchase contract with ConocoPhillips to offtake CO₂ from the Lost Cabin gas plant in Wyoming and are included in our Consolidated Balance Sheets under the caption “Other assets.” We amortize the CO₂ contract intangible asset on a straight-line basis over the contract term. Total amortization expense for our intangible assets was $2.4 million, $2.4 million and $2.4 million during the years ended December 31, 2019, 2018 and 2017. The following table summarizes the carrying value of our intangible assets as of December 31, 2019 and 2018:

		December 31,
In thousands		2019				2018
Intangible asset value		$	37,608			$	37,848
Accumulated amortization		(15,502		)		(13,074		)
Net book value		$	22,106			$	24,774

As of December 31, 2019, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows:

In thousands
2020		$	2,420
2021		2,420
2022		2,420
2023		2,420
2024		2,420

 

Impairment Assessment of Long-Lived Assets

The portion of our capitalized CO₂ costs related to CO₂ reserves and CO₂ pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues.  The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing whenever events or changes in circumstances indicate that the carrying value may not be recoverable.

We perform our long-lived asset impairment test by comparing the net carrying costs of our long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves. If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. We did not record an impairment of long-lived assets during the year ended December 31, 2019.

Asset Retirement Obligations

In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and CO₂ wells, removing equipment and facilities from leased acreage, and returning land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.  Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability.  If the liability for an oil or natural gas well is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant.

Asset retirement obligations are estimated at the present value of expected future net cash flows.  We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor and materials, profits on

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costs of labor and materials, the effect of inflation on estimated costs, and the discount rate.  Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurement topic.

Commodity Derivative Contracts

We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production.  These derivative contracts have historically consisted of options, in the form of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps.  Our derivative financial instruments, other than any derivative instruments that are designated under the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or a liability measured at fair value.  We do not apply hedge accounting to our commodity derivative contracts; accordingly, changes in the fair value of these instruments are recognized in “Commodity derivatives expense (income)” in our Consolidated Statements of Operations in the period of change.

Concentrations of Credit Risk

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above.  Our cash equivalents represent high-quality securities placed with various investment-grade institutions.  This investment practice limits our exposure to concentrations of credit risk.  Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited.  We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit.  We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification.  All of our derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders).  There are no margin requirements with the counterparties of our derivative contracts.

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price.  We would not expect the loss of any purchaser to have a material adverse effect upon our operations.  For the year ended December 31, 2019, three purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (32%), Hunt Crude Oil Supply Company (11%) and Sunoco Inc. (11%). For the year ended December 31, 2018, two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (24%) and Hunt Crude Oil Supply Company (10%). For the year ended December 31, 2017, two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (22%) and Marathon Petroleum Company (10%).

Other Receivables

During 2018, we recorded a $16.9 million impairment of a loan related to a proposed plant in the Gulf Coast that would potentially supply CO₂ to Denbury, due to uncertainties of the project achieving financial close. The impairment was included within “Other expenses” in our Consolidated Statements of Operations for the year ended December 31, 2018.

Income Taxes

Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position.  The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

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Net Income per Common Share

Basic net income per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of nonvested restricted stock, nonvested performance-based equity awards, and shares into which our convertible senior notes are convertible.

The following table sets forth the reconciliations of net income and weighted average shares used for purposes of calculating basic and diluted net income per common share for the periods indicated:

		Year Ended December 31,
In thousands		2019				2018				2017
Numerator
Net income – basic		$	216,959			$	322,698			$	163,152
Effect of potentially dilutive securities
Interest expensed on convertible senior notes including amortization of discount, net of tax		14,134				539				49
Net income – diluted		$	231,093			$	323,237			$	163,201
Denominator
Weighted average common shares outstanding – basic		459,524				432,483				390,928
Effect of potentially dilutive securities
Restricted stock and performance-based equity awards		2,396				6,500				2,242
Convertible senior notes(1)		48,421				17,186				2,751
Weighted average common shares outstanding – diluted		510,341				456,169				395,921

(1)	For the year ended December 31, 2019, shares shown under “convertible senior notes” represent the prorated portion of the approximately 90.9 million shares of the Company’s common stock issuable upon full conversion of our convertible senior notes which were issued on June 19, 2019 (see Note 6, Long-Term Debt – 2019 Debt Reduction Transactions).

Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share (although time-vesting restricted stock is issued and outstanding upon grant).  For purposes of calculating diluted weighted average common shares, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the earliest date outstanding during the respective periods. In April and May 2018, all of the then outstanding 3½% Convertible Senior Notes due 2024 and 5% Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes”) converted into shares of Denbury common stock, resulting in the issuance of 55.2 million shares of our common stock upon conversion. These shares have been included in basic weighted average common shares outstanding beginning on the date of conversion. See Note 6, Long-Term Debt, for further discussion.

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share, as their effect would have been antidilutive:

		Year Ended December 31,
In thousands		2019			2018			2017
Stock appreciation rights		2,027			2,743			4,512
Restricted stock and performance-based equity awards		5,505			1,234			5,645

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Environmental and Litigation Contingencies

The Company makes judgments and estimates in recording liabilities for contingencies such as environmental remediation or ongoing litigation.  Liabilities are recorded when it is both probable that a loss has been incurred and such loss is reasonably estimable.  Assessments of liabilities are based on information obtained from independent and in-house experts, loss experience in similar situations, actual costs incurred, and other case-by-case factors.  Any related insurance recoveries are recognized in our financial statements during the period received or at the time receipt is determined to be virtually certain.

Recent Accounting Pronouncements

Recently Adopted

Leases. Effective January 1, 2019, we adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU 2016-02”), and ASU 2018-01, Leases (Topic 842) – Land Easement Practical Expedient for Transition to Topic 842, using the modified retrospective method with an application date of January 1, 2019. ASU 2016-02 does not apply to mineral leases or leases that convey the right to explore for or use the land on which oil, natural gas, and similar natural resources are contained. We elected the practical expedients provided in the new ASUs that allow historical lease classification of existing leases, allow lease and non-lease components to be combined, and carry forward our accounting treatment for existing land easement agreements. The adoption of the new standards resulted in the recognition of $39.1 million of lease right-of-use assets and $55.8 million of operating lease liabilities ($16.7 million of which related to previously-existing lease obligations) as of January 1, 2019, in our Consolidated Balance Sheets, but did not materially impact our results of operations and had no impact on our cash flows. The additional lease right-of-use assets and operating lease liabilities recorded on our balance sheet primarily related to our leases for office space, as the accounting for our financing leases and pipeline financings was relatively unchanged.

Not Yet Adopted

Financial Instruments – Credit Losses. In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. We intend to adopt the standard using a modified retrospective approach with an application date of January 1, 2020. The adoption of ASU 2016-13 is not expected to have a material effect on our consolidated financial statements.

Fair Value Measurement.  In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820) – Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“ASU 2018-13”).  ASU 2018-13 adds, modifies, or removes certain disclosure requirements for recurring and nonrecurring fair value measurements based on the FASB’s consideration of costs and benefits. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the amendments on changes in unrealized gains and losses for Level 3 fair value measurements, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty prospectively, and all other amendments should be applied retrospectively to all periods presented. We plan to adopt the standard with an application date of January 1, 2020. The adoption of ASU 2018-13 is not expected to have a material effect on our consolidated financial statements but may require enhanced footnote disclosures.

Note 2. Revenue Recognition

We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. This principle is achieved through applying a five-step process for customer contract revenue recognition:

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•Identify the contract or contracts with a customer – We derive the majority of our revenues from oil and natural gas sales contracts and CO₂ sales and transportation contracts. The contracts specify each party’s rights regarding the goods or services to be transferred and contain commercial substance as they impact our financial statements. A high percentage of our receivables balance is current, and we have not historically entered into contracts with counterparties that pose a credit risk without requiring adequate economic protection to ensure collection.

•Identify the performance obligations in the contract – Each of our revenue contracts specify a volume per day, or production from a lease designated in the contract (a distinct good), to be delivered at the delivery point over the term of the contract (the identified performance obligation). The customer takes delivery and physical possession of the product at the delivery point, which generally is also the point at which title transfers and the customer obtains the risks and rewards of ownership (the identified performance obligation is satisfied).

•Determine the transaction price – Typically, our oil and natural gas contracts define the price as a formula price based on the average market price, as specified on set dates each month, for the specific commodity during the month of delivery. Certain of our CO₂ contracts define the price as a fixed contractual price adjusted to an inflation index to reflect market pricing. Given the industry practice to invoice customers the month following the month of delivery and our high probability of collection of payment, no significant financing component is included in our contracts.

•Allocate the transaction price to the performance obligations in the contract – The majority of our revenue contracts are short-term, with terms of one year or less, to which we have applied the practical expedient permitted under the standard eliminating the requirement to disclose the transaction price allocated to remaining performance obligations. In limited instances, we have revenue contracts with terms greater than one year; however, the future delivery volumes are wholly unsatisfied as they represent separate performance obligations with variable consideration. We utilized the practical expedient which eliminates the requirement to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to wholly unsatisfied performance obligations. As there is only one performance obligation associated with our contracts, no allocation of the transaction price is necessary.

•Recognize revenue when, or as, we satisfy a performance obligation – Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO₂ contracts is made within a month following product delivery and for natural gas and NGL contracts is generally made within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Consolidated Balance Sheets, which was $139.4 million and $125.8 million as of December 31, 2019 and December 31, 2018, respectively.

In addition to revenues from oil and natural gas sales contracts and CO₂ sales and transportation contracts, the Company enters into purchase transactions with third parties and separate sale transactions with third parties in the Gulf Coast region. Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.

Disaggregation of Revenue

The following table summarizes our revenues by product type for the years ended December 31, 2019, 2018 and 2017:

		Year Ended December 31,
In thousands		2019				2018				2017
Oil sales		$	1,205,083			$	1,412,358			$	1,079,703
Natural gas sales		6,937				10,231				9,963
CO2 sales and transportation fees		34,142				31,145				26,182
Purchased oil sales		14,198				1,921				3,718
Total revenues		$	1,260,360			$	1,455,655			$	1,119,566

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Note 3. Leases

We evaluate contracts for leasing arrangements at inception. We lease office space, equipment, and vehicles that have non-cancelable lease terms. Currently, our outstanding leases have remaining terms up to 6 years, with certain land leases having remaining terms up to 50 years.  Leases with a term of 12 months or less are not recorded on our balance sheet. During the third quarter of 2019, we exercised the early buyout option on our remaining finance leases. The table below reflects our operating lease right-of-use assets and operating lease liabilities, which primarily consists of our office leases:

		December 31,
In thousands		2019
Operating leases
Operating lease right-of-use assets		$	34,099
Operating lease liabilities - current		$	6,901
Operating lease liabilities - long-term		41,932
Total operating lease liabilities		$	48,833

The majority of our leases contain renewal options, typically exercisable at our sole discretion. We record right-of-use assets and liabilities based on the present value of lease payments over the initial lease term, unless the option to extend the lease is reasonably certain, and utilize our incremental borrowing rate based on information available at the lease commencement date. The following weighted average remaining lease terms and discount rates related to our outstanding operating leases:

		December 31,
		2019
Weighted average remaining lease term		5.7 years
Weighted average discount rate		6.7	%

Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the lease term. For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized separately, with the depreciable life reflective of the expected lease term. We have subleased part of the office space included in our operating leases. We expect to receive a total of approximately $10.4 million for 2020 through 2025 under our sublease agreements. The following table summarizes the components of lease costs and sublease income:

				Year Ended
In thousands		Income Statement		December 31, 2019
Operating lease cost		General and administrative expenses		$	8,924
		Lease operating expenses		58
		CO2 discovery and operating expenses		5
				$	8,987
Finance lease cost
Amortization of right-of-use assets		Depletion, depreciation, and amortization		$	1,188
Interest on lease liabilities		Interest expense		40
Total finance lease cost				$	1,228
Sublease income		General and administrative expenses		$	4,127

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Our statement of cash flows included the following activity related to our operating and finance leases:

		Year Ended
In thousands		December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases		$	10,995
Operating cash flows from interest on finance leases		40
Financing cash flows from finance leases		1,275
Right-of-use assets obtained in exchange for lease obligations
Operating leases		415
Finance leases		—

The following table summarizes by year the maturities of our minimum lease payments as of December 31, 2019, but excludes future sublease receipts associated with sublease contracts we have for a portion of these operating leases:

		Operating
In thousands		Leases
2020		$	9,934
2021		10,056
2022		10,259
2023		10,300
2024		10,317
Thereafter		8,287
Total minimum lease payments		59,153
Less: Amount representing interest		(10,320		)
Present value of minimum lease payments		$	48,833

The following table summarizes by year the remaining non-cancelable future payments under our leases, as accounted for under previous accounting guidance under FASC Topic 840, Leases, as of December 31, 2018:

		Operating
In thousands		Leases
2019		$	10,690
2020		9,776
2021		10,007
2022		10,223
2023		10,262
Thereafter		18,169
Total minimum lease payments		$	69,127

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The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2019 and 2018:

		Year Ended December 31,
In thousands		2019				2018
Beginning asset retirement obligations		$	176,585			$	166,310
Liabilities incurred and assumed during period		4,354				2,201
Revisions in estimated retirement obligations		9,206				2,298
Liabilities settled and sold during period		(24,342		)		(9,481		)
Accretion expense		15,957				15,257
Ending asset retirement obligations		181,760				176,585
Less: current asset retirement obligations(1)		(4,652		)		(2,115		)
Long-term asset retirement obligations		$	177,108			$	174,470

(1)	Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.

Liabilities assumed relate to minor acquisitions, with liabilities incurred generally relating to wells and facilities.

We have escrow accounts that are legally restricted for certain of our asset retirement obligations.  The balances of these escrow accounts were $53.4 million and $42.1 million as of December 31, 2019 and 2018, respectively.  These balances are primarily invested in U.S. Treasury bonds, recorded at amortized cost, and money market accounts, which investments are included in “Other assets” in our Consolidated Balance Sheets.  A portion of these investments are included in cash, cash equivalents, and restricted cash balances on our Consolidated Statements of Cash Flows (see Note 1, Nature of Operations and Summary of Significant Accounting Policies – Cash, Cash Equivalents, and Restricted Cash). The carrying value of these investments approximates their estimated fair market value as of December 31, 2019 and 2018.

Note 5. Unevaluated Property

A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at December 31, 2019, and the year in which the costs were incurred follows:

		December 31, 2019
		Costs Incurred During:
In thousands		2019				2018				2017				2016 and Prior				Total
Property acquisition costs		$	—			$	—			$	8,527			$	572,930			$	581,457
Exploration and development		3,522				1,862				3,175				108,268				116,827
Capitalized interest		31,489				27,013				23,134				92,990				174,626
Total		$	35,011			$	28,875			$	34,836			$	774,188			$	872,910

Our property acquisition costs for 2016 and prior were primarily related to the fair value allocated to the purchase of interests in the Cedar Creek Anticline (“CCA”) and Hartzog Draw, as well as CO₂ tertiary potential at Conroe Field. Exploration and development costs shown as unevaluated properties are primarily associated with our tertiary oil fields that are under development but did not have proved reserves at December 31, 2019.  The most significant development costs incurred during each period relate to development in preparation for the CO₂ floods at Webster, Conroe, and CCA fields. We have not yet recognized proved tertiary reserves in these fields.

Costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment determined.  We review the excluded properties for impairment at least annually.  We currently estimate that evaluation of the majority of these properties and the inclusion of their costs in the amortization base is expected to be completed

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within five to ten years.  Until we are able to determine whether there are any proved reserves attributable to the above costs, we are not able to assess the future impact on the amortization rate of the full cost pool.

Note 6. Long-Term Debt

The table below reflects long-term debt and capital lease obligations outstanding as of December 31, 2019 and 2018:

		December 31,
In thousands		2019				2018
Senior Secured Bank Credit Agreement		$	—			$	—
9% Senior Secured Second Lien Notes due 2021		614,919				614,919
9¼% Senior Secured Second Lien Notes due 2022		455,668				455,668
7¾% Senior Secured Second Lien Notes due 2024		531,821				—
7½% Senior Secured Second Lien Notes due 2024		20,641				450,000
6⅜% Convertible Senior Notes due 2024		245,548				—
6⅜% Senior Subordinated Notes due 2021		51,304				203,545
5½% Senior Subordinated Notes due 2022		58,426				314,662
4⅝% Senior Subordinated Notes due 2023		135,960				307,978
Pipeline financings		167,439				180,073
Capital lease obligations		—				5,362
Total debt principal balance		2,281,726				2,532,207
Debt discount(1)		(101,767		)		—
Future interest payable(2)		164,914				250,218
Debt issuance costs		(10,009		)		(13,089		)
Total debt, net of debt issuance costs and discount		2,334,864				2,769,336
Less: current maturities of long-term debt(3)		(102,294		)		(105,125		)
Long-term debt and capital lease obligations		$	2,232,570			$	2,664,211

(1)	Consists of discounts related to the issuance during June 2019 of our new 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) and new 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) of $27.0 million and $74.8 million, respectively (see 2019 Debt Reduction Transactions below) as of December 31, 2019.

(2)	Future interest payable represents most of the interest due over the terms of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors.

(3)	Our current maturities of long-term debt as of December 31, 2019 include $86.1 million of future interest payable related to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months.

The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all our outstanding senior secured, convertible senior, and senior subordinated notes.  DRI has no independent assets or operations.  Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of such notes are minor subsidiaries.

Senior Secured Bank Credit Facility

In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2021, provided that the maturity date may occur earlier (February 12, 2021, May 14, 2021 or August 13, 2021) if the 2021 Senior Secured Notes due in May 2021 or 6⅜% Senior Subordinated Notes due in August 2021 (the “2021 Senior Subordinated Notes”), respectively, are not repaid or refinanced by each of their respective maturity dates. As of December 31, 2019, the borrowing base and lender commitments for the revolving credit facility were $615 million, and scheduled redeterminations of the borrowing base are to occur semiannually in May and

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November of each year, with the next such redetermination being scheduled for May 2020. If our outstanding debt under the Bank Credit Agreement were to ever exceed the borrowing base, we would be required to repay the excess amount over a period not to exceed six months. Under the Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million, which may be increased at the sole discretion of the administrative agent, and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available commitments under the Bank Credit Agreement. The Bank Credit Agreement is guaranteed jointly and severally by each subsidiary of DRI that is 100% owned, directly or indirectly, by DRI and is secured by (1) a significant portion of our proved oil and natural gas properties held through DRI’s restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; (3) a pledge of commodity derivative agreements of DRI and such subsidiaries (as applicable); and (4) a pledge of deposit accounts, securities accounts and commodity accounts of DRI and such subsidiaries (as applicable).

The Bank Credit Agreement limits our ability to, among other things, incur and repay indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make distributions and dividends; and enter into commodity derivative agreements, in each case subject to customary exceptions.

The Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following:

•	A Consolidated Total Debt to Consolidated EBITDAX financial maintenance covenant, with such ratio not to exceed 5.25 to 1.0 through December 31, 2020 and 4.50 to 1.0 thereafter;

•	A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 2.5 to 1.0. Only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;

•	A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and

•	A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0 to 1.0.

For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include borrowing base availability under the senior secured bank credit facility, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding.

As of December 31, 2019, (1) loans under the Bank Credit Agreement were subject to varying rates of interest based on either (a) for ABR Loans, a base rate determined under the Bank Credit Agreement (the “ABR”) plus an applicable margin ranging from 1.75% to 2.75% per annum, or (b) for LIBOR Loans, the LIBOR rate plus an applicable margin ranging from 2.75% to 3.75% per annum (capitalized terms as defined in the Bank Credit Agreement) and (2) the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement was subject to a commitment fee of 0.50%. As of December 31, 2019, we had no outstanding borrowings, $87.2 million of letters of credit outstanding and were in compliance with all debt covenants under the Bank Credit Agreement.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and the amendments thereto, each of which are filed as exhibits to our periodic reports filed with the SEC.

2019 Debt Reduction Transactions

During the third quarter of 2019, we repurchased $11.0 million in aggregate principal amount of our then outstanding 5½% Senior Subordinated Notes due 2022 (the “2022 Senior Subordinated Notes”) in open market transactions for a total purchase price of $5.3 million, excluding accrued interest. Additionally, during the fourth quarter of 2019, we repurchased principally through exchanges an additional $25.3 million in aggregate principal amount of our then outstanding 2022 Senior Subordinated Notes and $75.7 million in aggregate principal amount of our then outstanding 4⅝% Senior Subordinated Notes due 2023 (the “2023 Senior Subordinated Notes”) for $11.2 million in cash and issuance of 38.3 million shares of the Company’s common stock. In connection with these transactions, we recognized a $55.5 million gain on debt extinguishment, net of unamortized debt issuance costs written off, during the year ended December 31, 2019, in our Consolidated Statements of Operations.

During June 2019, in a series of debt exchanges, we extended the maturities of our outstanding long-term debt and reduced the amount of our outstanding debt principal. As part of these transactions, holders exchanged a total of $468.4 million aggregate

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principal amount of our then outstanding senior subordinated notes for $102.6 million aggregate principal amount of new 7¾% Senior Secured Notes, $245.5 million aggregate principal amount of new 2024 Convertible Senior Notes and $120.0 million of cash. The exchanged senior subordinated notes consisted of $152.2 million aggregate principal amount of our 2021 Senior Subordinated Notes, $219.9 million aggregate principal amount of our 2022 Senior Subordinated Notes and $96.3 million aggregate principal amount of our 2023 Senior Subordinated Notes. In addition, holders also exchanged $425.4 million of 7½% Senior Secured Second Lien Notes due 2024 (the “7½% Senior Secured Notes”) for $425.4 million aggregate principal amount of 7¾% Senior Secured Notes. In July 2019, holders exchanged an additional $4.0 million aggregate principal amount of 7½% Senior Secured Notes for $3.8 million aggregate principal amount of 7¾% Senior Secured Notes. As a result, we recognized a noncash gain on debt extinguishment, net of transaction costs, totaling $100.5 million for the year ended December 31, 2019, in our Consolidated Statements of Operations.

In accordance with FASC 470-50, Modifications and Extinguishments, the June 2019 exchange of our existing senior subordinated notes was accounted for as a debt extinguishment. Therefore, our new 7¾% Senior Secured Notes and new 2024 Convertible Senior Notes were recorded on our balance sheet at fair market value based upon initial trading prices following their issuance, resulting in a discount to their principal amount of $22.6 million and $79.9 million, respectively. These debt discounts will be amortized as interest expense over the terms of these notes.

Separately, the June 2019 exchange of our existing senior secured second lien notes was accounted for as a modification of those notes. Therefore, no gain or loss was recognized, and previously deferred debt issuance costs of $6.9 million were treated as a discount to the principal amount of the new 7¾% Senior Secured Notes, which discount will be amortized as interest expense over the term of these notes.

January 2018 Senior Subordinated Note Exchanges

During January 2018, we closed transactions to exchange a total of $174.3 million aggregate principal amount of our then existing senior subordinated notes for $74.1 million aggregate principal amount of new 2022 Senior Secured Notes and $59.4 million aggregate principal amount of our previously outstanding 2023 Convertible Senior Notes, resulting in a net reduction in our debt principal from these exchanges of $40.8 million. The exchanged notes consisted of $11.6 million aggregate principal amount of our 2021 Senior Subordinated Notes, $94.2 million aggregate principal amount of our 2022 Senior Subordinated Notes and $68.5 million aggregate principal amount of our 2023 Senior Subordinated Notes. In May 2018, the debt principal balance and future interest applicable to the 2023 Convertible Senior Notes were reclassified to “Paid-in capital in excess of par” and “Common stock” in our Consolidated Balance Sheets following the conversion of the notes into shares of Denbury common stock (see Conversions of 2023 and 2024 Convertible Senior Notes into Common Stock in April and May 2018 below for further discussion).

2017 Senior Subordinated Note Exchanges

During December 2017, we entered into privately negotiated agreements to exchange a total of $609.8 million aggregate principal amount of our existing senior subordinated notes for $381.6 million aggregate principal amount of new 2022 Senior Secured Notes and $84.7 million aggregate principal amount of 3½% Convertible Senior Notes due 2024, resulting in a net reduction in our debt principal from these exchanges of $143.6 million. The exchanged notes consisted of $364.0 million aggregate principal amount of our 2022 Senior Subordinated Notes and $245.8 million aggregate principal amount of our 2023 Senior Subordinated Notes.

Conversions of 2023 and 2024 Convertible Senior Notes into Common Stock in April and May 2018

During the second quarter of 2018, holders of all $59.4 million aggregate principal amount outstanding of our 2023 Convertible Senior Notes and $84.7 million aggregate principal amount outstanding of our 3½% Convertible Senior Notes due 2024 converted their notes into shares of Denbury common stock, at the rates specified in the indentures for these notes, resulting in the issuance of 55.2 million shares of our common stock upon conversion. The debt principal balances and future interest treated as debt applicable to the 2023 Convertible Senior Notes and 3½% Convertible Senior Notes due 2024, totaling $162.0 million, were reclassified to “Paid-in capital in excess of par” and “Common stock” in our Consolidated Balance Sheets upon the conversion of the notes into shares of Denbury common stock. As of April 18, 2018 and May 30, 2018, there were no remaining 3½% Convertible Senior Notes due 2024 and 2023 Convertible Senior Notes outstanding, respectively.

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Senior Secured Second Lien Notes

9% Senior Secured Second Lien Notes due 2021. In May 2016, we issued $614.9 million of 2021 Senior Secured Notes.  The 2021 Senior Secured Notes, which bear interest at a rate of 9% per annum, were issued at par in connection with privately negotiated exchanges with a limited number of holders of existing senior subordinated notes.  The 2021 Senior Secured Notes mature on May 15, 2021, and interest is payable semiannually in arrears on May 15 and November 15 of each year.  At any time prior to December 15, 2020, we may redeem the 2021 Senior Secured Notes in whole or in part at our option, at a redemption price of 104.50% of the principal amount, and at par thereafter, as specified in the indenture. The 2021 Senior Secured Notes are not subject to any sinking fund requirements.

The 2021 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt.

9¼% Senior Secured Second Lien Notes due 2022. In December 2017 and January 2018, we issued $381.6 million and $74.1 million, respectively, of 2022 Senior Secured Notes.  The 2022 Senior Secured Notes, which bear interest at a rate of 9.25% per annum, were issued at par in connection with exchanges with a limited number of holders of existing senior subordinated notes (see January 2018 Senior Subordinated Note Exchanges and 2017 Senior Subordinated Note Exchanges above).  The 2022 Senior Secured Notes mature on March 31, 2022, and interest is payable semiannually in arrears on March 31 and September 30 of each year.  We may redeem the 2022 Senior Secured Notes in whole or in part at our option, at a redemption price of 109.25% of the principal amount at any time prior to March 31, 2020, 104.625% of the principal amount prior to March 31, 2021, and at par thereafter. The 2022 Senior Secured Notes are not subject to any sinking fund requirements.

The 2022 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt.

7¾% Senior Secured Second Lien Notes due 2024. In June 2019, we issued $528.0 million of 7¾% Senior Secured Notes in connection with exchanges with certain holders of the Company’s outstanding senior subordinated notes and existing 7½% Senior Secured Notes (see 2019 Debt Reduction Transactions above). The 7¾% Senior Secured Notes, which carry a stated interest rate of 7.75% per annum, were recorded at approximately 94% of their principal amount in accordance with FASC 470-50, Modifications and Extinguishments, which equates to an effective yield to maturity of approximately 9.39%. In July 2019, we issued an additional $3.8 million of 7¾% Senior Secured Notes in exchange for $4.0 million of 7½% Senior Secured Notes, which were recorded at par. The 7¾% Senior Secured Notes mature on February 15, 2024, and interest is payable semiannually in arrears on February 15 and August 15 of each year. We may redeem the 7¾% Senior Secured Notes in whole or in part at our option beginning August 15, 2020, at a redemption price of 103.875% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 7¾% Senior Secured Notes. Prior to August 15, 2020, we may at our option redeem up to an aggregate of 35% of the principal amount of the 7¾% Senior Secured Notes at a price of 107.75% of par with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2020, we may redeem the 7¾% Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The 7¾% Senior Secured Notes are not subject to any sinking fund requirements.

The 7¾% Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt.

7½% Senior Secured Second Lien Notes due 2024. In August 2018, we issued $450.0 million of 7½% Senior Secured Notes. The 7½% Senior Secured Notes, which bear interest at a rate of 7.50% per annum, were issued at par to repay outstanding borrowings on our Bank Credit Agreement, with additional proceeds used for general corporate purposes. After note exchanges completed in June and July of 2019, $20.6 million principal amount of the 7½% Senior Secured Notes remained outstanding as of December 31, 2019. The 7½% Senior Secured Notes mature on February 15, 2024, and interest is payable semiannually in arrears on February 15 and August 15 of each year. We may redeem the 7½% Senior Secured Notes in whole or in part at our

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option beginning August 15, 2020, at a redemption price of 103.75% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 7½% Senior Secured Notes. Prior to August 15, 2020, we may at our option redeem up to an aggregate of 35% of the principal amount of the 7½% Senior Secured Notes at a price of 107.50% of par with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2020, we may redeem the 7½% Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The 7½% Senior Secured Notes are not subject to any sinking fund requirements.

The 7½% Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt.

Restrictive Covenants in Indentures for Senior Secured Second Lien Notes. Each of the indentures for the 2021 Senior Secured Notes, 2022 Senior Secured Notes, 7¾% Senior Secured Notes and 7½% Senior Secured Notes contains customary covenants that are generally consistent and that restrict our ability and the ability of our restricted subsidiaries to (1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create limitations on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt (including existing senior subordinated notes)), provided that in certain circumstances we may make unlimited restricted payments so long as we maintain a Leverage Ratio (as defined in the indentures) not to exceed 2.5 to 1.0 (both before and after giving effect to any restricted payment). As of December 31, 2019, we were in compliance with all debt covenants under the indentures related to our senior secured second lien notes.

Convertible Senior Notes

6⅜% Convertible Senior Notes due 2024. In June 2019, we issued $245.5 million of 2024 Convertible Senior Notes in connection with exchanges with certain holders of the Company’s outstanding senior subordinated notes (see 2019 Debt Reduction Transactions above). The 2024 Convertible Senior Notes, which carry a stated interest rate of 6.375% per annum, were recorded at approximately 67% of their principal amount in accordance with FASC 470-50, Modifications and Extinguishments, which equates to an effective yield to maturity of approximately 15.31%. Interest on the 2024 Convertible Senior Notes is payable semiannually in arrears on June 30 and December 30 of each year and mature on December 31, 2024. We do not have the right to redeem the 2024 Convertible Senior Notes prior to their maturity. The 2024 Convertible Senior Notes are convertible into shares of our common stock at any time, at the option of the holders, at a rate of 370 shares of common stock per $1,000 principal amount of 2024 Convertible Senior Notes, which is equivalent to approximately 90.9 million shares of the Company’s common stock, subject to customary adjustments to the conversion rate and threshold price with respect to, among other things, stock dividends and distributions, mergers and reclassifications. The 2024 Convertible Senior Notes will be automatically converted into shares of common stock at this rate if the volume weighted average trading price of the Company’s common stock equals or exceeds the threshold price, which is $2.43 per share, for 10 trading days in any period of 15 consecutive trading days, subject to satisfaction of certain other conditions. Additionally, the Company may, based on a determination of its Board of Directors that such changes are in the best interests of the Company, and subject to certain limitations, increase the conversion rate. Any such conversion rate increase would cause a proportional decrease in the threshold price for mandatory conversions, and thereby would enable the Company to require a mandatory conversion into common stock at a lower price.

Restrictive Covenants in Indentures for Convertible Senior Notes. The indenture for the 2024 Convertible Senior Notes contains certain covenants that restrict our ability and the ability of our restricted subsidiaries to take or permit certain actions, including restrictions on our ability and the ability of our restricted subsidiaries to (1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt), provided that in certain circumstances we may make unlimited restricted payments so long as we maintain a Leverage Ratio (both as defined in the indenture) not to exceed 2.5 to 1.0

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(both before and after giving effect to any restricted payment). As of December 31, 2019, we were in compliance with all debt covenants under the indenture related to our convertible senior notes.

Senior Subordinated Notes

6⅜% Senior Subordinated Notes due 2021. In February 2011, we issued $400 million of 2021 Senior Subordinated Notes.  The 2021 Senior Subordinated Notes, which bear interest at a rate of 6.375% per annum, were sold at par. After note repurchases in open market transactions and exchange transactions completed over the last four years, $51.3 million principal amount of the 2021 Senior Subordinated Notes remained outstanding as of December 31, 2019. The 2021 Senior Subordinated Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year.  We may redeem the 2021 Senior Subordinated Notes in whole or in part at our option at a redemption price of 100% of the principal amount.

5½% Senior Subordinated Notes due 2022. In April 2014, we issued $1.25 billion of 2022 Senior Subordinated Notes. The 2022 Senior Subordinated Notes, which bear interest at a rate of 5.5% per annum, were sold at par. After note repurchases in open market transactions and exchange transactions completed over the last four years, $58.4 million principal amount of the 2022 Senior Subordinated Notes remained outstanding as of December 31, 2019. The 2022 Senior Subordinated Notes mature on May 1, 2022, and interest is payable on May 1 and November 1 of each year. At any time prior to May 1, 2020, we may redeem the 2022 Senior Subordinated Notes in whole or in part at our option, at a redemption price of 101.375% of the principal amount, and at par thereafter, as specified in the indenture. The 2022 Senior Subordinated Notes are not subject to any sinking fund requirements.

4⅝% Senior Subordinated Notes due 2023. In February 2013, we issued $1.2 billion of 2023 Senior Subordinated Notes. The 2023 Senior Subordinated Notes, which bear interest at a rate of 4.625% per annum, were sold at par. After note repurchases in open market transactions and exchange transactions completed over the last four years, $136.0 million principal amount of the 2023 Senior Subordinated Notes remained outstanding as of December 31, 2019. The 2023 Senior Subordinated Notes mature on July 15, 2023, and interest is payable on January 15 and July 15 of each year. At any time prior to January 15, 2021, we may redeem the 2023 Senior Subordinated Notes in whole or in part at our option at a redemption price of 100.771% of the principal amount, and at par thereafter, as specified in the indenture. The 2023 Senior Subordinated Notes are not subject to any sinking fund requirements.

Restrictive Covenants in Indentures for Senior Subordinated Notes. Each of the indentures for the 2021 Senior Subordinated Notes, 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes contains certain covenants that are generally consistent and that restrict our ability and the ability of our restricted subsidiaries to take or permit certain actions, including restrictions on our ability and the ability of our restricted subsidiaries to (1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt), provided that the restricted payments covenant in the indentures for the 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes permits us in certain circumstances to make unlimited restricted payments so long as we maintain a Leverage Ratio (both as defined in the 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes Indentures) not to exceed 2.5 to 1.0 (both before and after giving effect to any restricted payment), although we will not be able to realize the practical benefit of the restricted payment covenant flexibility in the 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes Indentures until the 2021 Senior Subordinated Notes have been redeemed or retired. As of December 31, 2019, we were in compliance with all debt covenants under the indentures related to our senior subordinated notes.

Pipeline Financings

In May 2008, we closed two transactions with Genesis Energy, L.P. (“Genesis”) involving two of our pipelines.  The NEJD Pipeline system included a 20-year financing, and the Free State Pipeline included a long-term transportation service agreement.  These transactions are both accounted for as financing arrangements under FASC Topic 840, Leases.

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Debt Issuance Costs

In connection with the issuance of our outstanding long-term debt, we have incurred debt issuance costs, which are being amortized to interest expense using the straight line or effective interest method over the term of each related facility or borrowing.  Remaining unamortized debt issuance costs were $14.0 million and $19.1 million at December 31, 2019 and 2018, respectively.  Issuance costs associated with our Bank Credit Agreement are included in “Other assets” in our Consolidated Balance Sheets, and issuance costs associated with our senior secured second lien notes, convertible senior notes, and senior subordinated notes are included as a reduction of “Long-term debt, net of current portion” in our Consolidated Balance Sheets.

Indebtedness Repayment Schedule

At December 31, 2019, our indebtedness, including our financing lease obligations but excluding future interest payable treated as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors, is payable over the next five years and thereafter as follows (assuming our 2024 Convertible Senior Notes do not convert into shares of our common stock prior to maturity):

Note 7. Income Taxes

Our income tax provision (benefit) is as follows:

		Year Ended December 31,
In thousands		2019				2018				2017
Current income tax expense (benefit)
Federal		$	2,645			$	(17,885	)		$	(19,485	)
State		1,236				1,884				(1,388		)
Total current income tax expense (benefit)		3,881				(16,001		)		(20,873		)
Deferred income tax expense (benefit)
Federal		89,950				93,395				(113,863		)
State		10,521				9,839				18,084
Total deferred income tax expense (benefit)		100,471				103,234				(95,779		)
Total income tax expense (benefit)		$	104,352			$	87,233			$	(116,652	)

At December 31, 2019, we had no federal net operating loss carryforwards (“NOLs”), tax effected business interest expense carryforward totaling $24.5 million (before provision for valuation allowance), state NOLs and tax credits totaling $52.9 million (before provision for valuation allowance), an estimated $49.9 million of enhanced oil recovery credits to carry forward related to our tertiary operations, an estimated $21.6 million of research and development credits, and $6.0 million of alternative minimum tax credits.  Under the Tax Cut and Jobs Act (“the Act”) enacted in December 2017, all of our alternative minimum tax credits are fully refundable by 2021 and are recorded as a receivable on the balance sheet. We considered our assessment of the recorded tax benefit associated with the impacts of the Act to be substantially complete as of December 31, 2018, which is reflected in the table reconciling income tax expense below. Federal and state regulatory guidance of the Act are continuing to be issued and could result in further tax effects but are not expected to be material to our financial statements. In addition, the Tax Cut and Jobs Act

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revised the rules regarding the deductibility of business interest expense by limiting that deduction to 30% of adjusted taxable income (as defined), with disallowed amounts being carried forward to future taxable years. Based on our evaluation, using information existing as of the balance sheet date, of the near-term ability to utilize the tax benefits associated with our 2019 and 2018 disallowed business interest expense, we have established a valuation allowance of $24.5 million for that portion of our business interest expense that is currently expected to exceed the allowed limitation under the Act. Our business interest expense carryforward does not expire. Our state NOLs expire in various years, starting in 2020, although most do not begin to expire until 2025. Our enhanced oil recovery credits and research and development credits begin to expire in 2025 and 2031, respectively.

Deferred income taxes reflect the available tax carryforwards and the temporary differences based on tax laws and statutory rates in effect at the December 31, 2019 and 2018 balance sheet dates.  As of December 31, 2019, we had $52.7 million of deferred tax assets associated with State of Louisiana, Mississippi and Alabama net operating losses and tax credits. A tax valuation allowance was recorded in 2015 to reduce the carrying value of our Louisiana deferred tax assets as the result of a tax law enacted in the State of Louisiana, which limits a company’s utilization of certain deductions, including our net operating loss carryforwards. As of December 31, 2019, tax valuation allowances totaling $41.3 million were recorded for our State of Louisiana deferred tax assets. Based on losses from falling commodity prices and lower future forecasted income related to our Mississippi deferred tax assets, we concluded it was not more likely than not that the deferred tax assets would be realized. Accordingly, we recorded a valuation allowance against our Mississippi deferred tax assets in 2017. As of December 31, 2019, tax valuation allowances totaling $10.6 million were recorded for our State of Mississippi deferred tax assets. During 2019, we recorded a valuation allowance against our Alabama deferred tax assets totaling $0.8 million. After closing on the sale of our Citronelle Field in 2019, our ability to utilize our Alabama net operating losses will be limited, and we concluded it was not more likely than not that the deferred tax assets would be realized. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized. The changes in our valuation allowance established for our state net operating losses and business interest expense carryforward for 2019, 2018, and 2017 are detailed below:

		Year Ended December 31,
In thousands		2019				2018				2017
Balance at beginning of year		$	51,093			$	51,134			$	36,510
Federal		23,124				—				—
State		2,998				(41		)		14,624
Balance at end of year		$	77,215			$	51,093			$	51,134

As of December 31, 2019, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position.  The unrecognized tax benefit was recorded during 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate.  The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position.  We currently do not expect a material change to the uncertain tax position within the next 12 months.  Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, no such amounts were accrued related to the uncertain tax position as of December 31, 2019.

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Significant components of our deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows:

		December 31,
In thousands		2019				2018
Deferred tax assets
Loss and tax credit carryforwards – state		$	52,917			$	52,366
Business interest expense carryforward		24,513				9,049
Business credit carryforwards		71,555				79,528
Unrecognized gain and original issue discount on debt exchange		41,556				73,937
Accrued liabilities and other reserves		29,788				25,231
Other		18,725				23,208
Valuation allowances		(77,215		)		(51,093		)
Total deferred tax assets		161,839				212,226
Deferred tax liabilities
Property and equipment		(569,254		)		(492,214		)
Derivative contracts		(1,120		)		(23,127		)
Other		(1,695		)		(6,643		)
Total deferred tax liabilities		(572,069		)		(521,984		)
Total net deferred tax liability		$	(410,230	)		$	(309,758	)

Our reconciliation of income tax expense computed by applying the U.S. federal statutory rate and the reported effective tax rate on income from continuing operations is as follows:

		Year Ended December 31,
In thousands		2019				2018				2017
Income tax provision calculated using the federal statutory income tax rate		$	67,475			$	86,086			$	16,275
State income taxes, net of federal income tax benefit		7,435				11,968				2,764
Tax shortfall (windfall) on stock-based compensation deduction		1,912				(1,565		)		5,567
Valuation allowance		26,122				(42		)		5,562
Enhanced oil recovery tax credits generated		—				(10,818		)		(11,307		)
Re-measurement of deferreds related to federal tax rate change		—				—				(132,224		)
Other		1,408				1,604				(3,289		)
Total income tax expense (benefit)		$	104,352			$	87,233			$	(116,652	)

 

We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions.  The statutes of limitation for our income tax returns for tax years ending prior to 2016 have lapsed and therefore are not subject to examination by respective taxing authorities. We have not paid any significant interest or penalties associated with our income taxes.

Note 8. Stockholders’ Equity

401(k) Plan

We offer a 401(k) plan to which employees may contribute earnings subject to IRS limitations.  We match 100% of an employee’s contribution, up to 6% of compensation, as defined by the plan, which is vested immediately.  During 2019, 2018 and 2017, our matching contributions to the 401(k) plan were approximately $6.3 million, $6.2 million and $7.1 million, respectively.

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Note 9. Stock Compensation

The Amended and Restated 2004 Omnibus Stock and Incentive Plan, amended and restated as of March 28, 2019 (the “2004 Plan”), is an incentive plan that provides for the issuance of incentive and non-qualified stock options, restricted stock awards, restricted stock units, stock appreciation rights (“SARs”) settled in stock, and performance-based awards to officers, employees and directors. Since the 2004 Plan’s inception, awards covering a total of 61.4 million shares of common stock have been authorized for issuance pursuant to the 2004 Plan.  As of December 31, 2019, 13.6 million shares were available under the 2004 Plan for future issuance of awards, all of which could be issued in the form of restricted stock or performance-based awards.  Our incentive compensation program is administered by the Compensation Committee of our Board of Directors. The 2004 Plan was last approved by our stockholders in May 2019 and will expire in May 2029.

Stock-based compensation expense is included in “General and administrative expenses” in the Consolidated Statements of Operations.  Stock-based compensation associated with our employees involved in exploration and drilling activities is capitalized as part of “Oil and natural gas properties” in the Consolidated Balance Sheets. Our accounting policy is to account for forfeitures as they occur.

Stock-based compensation costs for the years ended December 31, 2019, 2018 and 2017, are as follows:

		Year Ended December 31,
In thousands		2019				2018				2017
Stock-based compensation expense included in G&A		$	12,470			$	11,951			$	15,154
Stock-based compensation capitalized		4,018				3,487				4,567
Total cost of stock-based compensation arrangements		$	16,488			$	15,438			$	19,721
Income tax benefit recognized for stock-based compensation arrangements		$	3,118			$	2,988			$	5,759

SARs

Prior to January 1, 2016, we granted SARs settled in stock to our employees. The SARs generally become exercisable over a three-year vesting period, with the specific terms of vesting determined at the time of grant based on guidelines established by the Compensation Committee of the Board of Directors.  The SARs expire over terms not to exceed 7 years from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending on the award, or one year after the death of the optionee.  The SARs were granted with a strike price equal to the fair market value at the time of grant, which is generally defined as the closing price on the NYSE on the date of grant.

The following is a summary of our SAR activity:

		Number of Awards			Weighted Average Exercise Price				Weighted Average Remaining Contractual Life (in years)		Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2018		2,500,885			$	10.41
Granted		—			—
Exercised		—			—
Forfeited		—			—
Expired		(519,729	)		15.29
Outstanding at December 31, 2019		1,981,156			9.12				1.5		$	—
Exercisable at end of period		1,981,156			$	9.12			1.5		$	—

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The following is a summary of the total intrinsic value of SARs exercised and grant-date fair value of SARs vested:

		Year Ended December 31,
In thousands		2019				2018				2017
Intrinsic value of SARs exercised		$	—			$	—			$	—
Grant-date fair value of SARs vested		—				1,095				1,818

 

As of December 31, 2018, all SARs vested and there was no remaining compensation cost to be recognized in future periods related to nonvested share-based SAR compensation arrangements. There were no exercises of SARs for the years ended December 31, 2019, 2018 or 2017.

Restricted Stock

We grant non-performance-based restricted stock to employees and directors as part of our long-term compensation program. Holders of non-performance-based restricted stock awards have the rights of owning non-restricted stock (including voting rights) except that the holders are not entitled to delivery of a portion thereof until certain requirements are met.  Beginning in 2014, non-performance-based restricted stock awards provide the holders with forfeitable dividend equivalent rights which vests with the underlying shares. Non-performance-based restricted stock vests over a three-year vesting period, with the specific terms of vesting determined at the time of grant.

As of December 31, 2019, there was $17.4 million of unrecognized compensation expense related to nonvested non-performance-based restricted stock grants.  This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.0 years.  The following is a summary of the total vesting date fair value of non-performance-based restricted stock:

		Year Ended December 31,
In thousands		2019				2018				2017
Fair value of restricted stock vested		$	5,743			$	23,060			$	9,325

A summary of the status of our nonvested non-performance-based restricted stock grants issued, and the changes during the year ended December 31, 2019, is presented below:

		Number of Shares			Weighted Average Grant-Date Fair Value
Nonvested at December 31, 2018		8,990,578			$	3.40
Granted		9,630,155			1.15
Vested		(4,612,265	)		3.20
Forfeited		(1,601,032	)		2.05
Nonvested at December 31, 2019		12,407,436			1.91

Performance-Based Equity Awards

Annually, the Compensation Committee of the Board of Directors grants performance-based equity awards to Denbury’s officers.  Performance-based awards generally vest over 1.25 to 3.25 years for awards granted in 2017 and over 3.25 years for awards granted in 2018 and 2019. The number of performance-based shares earned (and eligible to vest) during the performance period will depend upon: (1) our level of success in achieving specifically identified performance targets (“Performance-Based Operational Awards”) and (2) performance of our stock relative to that of a designated peer group (“Performance-Based TSR Awards”).  Generally, one-half of the maximum number of shares that could be earned under the performance-based awards will be earned for performance at the designated target levels (100% target vesting levels) or upon any earlier change of control, and twice the target number of shares will be earned if the maximum target levels are met (200% of target vesting levels).  With respect to the performance-based equity awards, any amounts earned above the 100% target levels will be payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan. If performance is below the designated minimum

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levels, no performance-based shares will be earned.  Performance-Based Operational Awards are valued using the fair market value of Denbury stock, and Performance-Based TSR Awards are valued using a Monte Carlo simulation.

As of December 31, 2019, there was $5.7 million of unrecognized compensation expense related to nonvested performance-based equity awards.  This unrecognized compensation cost is expected to be recognized over a weighted-average period of 1.9 years.  The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-Based TSR Awards (presented at the target level) are as follows:

		Year Ended December 31,
		2019				2018				2017
Weighted average fair value of Performance-Based TSR Awards granted		$	1.95			$	2.29			$	3.42
Risk-free interest rate		2.27		%		2.37		%		1.49		%
Expected life		3.0 years				3.0 years				3.0 years
Expected volatility		77.2		%		102.9		%		94.7		%
Dividend yield		—		%		—		%		—		%

A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the year ended December 31, 2019, is as follows:

		Performance-Based Operational Awards							Performance-Based TSR Awards
		Number of Awards			Weighted Average Grant-Date Fair Value				Number of Awards			Weighted Average Grant-Date Fair Value
Nonvested at December 31, 2018		857,812			$	2.43			3,806,116			$	2.71
Granted(1)		980,772			2.13				2,027,660			1.95
Vested(2)		—			—				(1,357,778	)		1.78
Forfeited		—			—				—			—
Nonvested at December 31, 2019		1,838,584			2.27				4,475,998			2.65

(1)	Amounts granted reflect the number of performance units granted. The actual payout of the shares may be between 0% and 200%, with any amounts earned above the 100% target levels payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan.

(2)	During 2019, the service period lapsed on these TSR performance unit awards. The lapsed units earned a weighted average of 100% of target for each vested TSR performance-based award, representing 1,357,778 aggregate shares of common stock issued. There were no vestings related to Operational performance-based awards during 2019.

The following is a summary of the total vesting date fair value of performance-based equity awards:

		Year Ended December 31,
In thousands		2019				2018				2017
Vesting date fair value of Performance-Based Operational Awards		$	—			$	595			$	1,079
Vesting date fair value of Performance-Based TSR Awards		2,783				542				227

Note 10. Commodity Derivative Contracts

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change.  These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Consolidated Statements of Operations.

Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our

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future cash flows.  We do not hold or issue derivative financial instruments for trading purposes.  Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps.  The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of December 31, 2019, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

The following table summarizes our commodity derivative contracts as of December 31, 2019, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:

Months		Index Price		Volume (Barrels per day)		Contract Prices ($/Bbl)
						Range(1)							Weighted Average Price
													Swap				Sold Put				Floor				Ceiling
Oil Contracts:
2020 Fixed-Price Swaps
Jan – Dec		NYMEX		2,000		$	60.00		–	61.00			$	60.59			$	—			$	—			$	—
Jan – Dec		Argus LLS		4,500			60.72		–	64.26			62.29				—				—				—
2020 Three-Way Collars(2)
Jan – June		NYMEX		23,000		$	55.00		–	82.65			$	—			$	48.25			$	56.95			$	62.83
Jan – June		Argus LLS		10,000			58.00		–	87.10			—				52.85				61.52				68.21
July – Dec		NYMEX		21,000			55.00		–	82.65			—				48.26				56.85				62.68
July – Dec		Argus LLS		8,000			58.00		–	87.10			—				52.75				61.08				68.39

(1)	Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.

(2)

A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

Note 11. Fair Value Measurements

The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”).  We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated or generally unobservable.  We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information.  Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  We are able to classify fair value balances based on the observability of those inputs.  The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  The three levels of the fair value hierarchy are as follows:

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•	Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.

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Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date.  Level 2 includes those financial instruments that are valued using models or other valuation methodologies.  Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet).  Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures.  Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

•

Level 3 – Pricing inputs include significant inputs that are generally less observable.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.  As of December 31, 2019, instruments in this category included non-exchange-traded three-way collars that were based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars were consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments were developed using a benchmark, which was considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $300 thousand in the fair value of these instruments as of December 31, 2019.

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions.  We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 and 2018:

		Fair Value Measurements Using:
		Quoted Prices in Active Markets				Significant Other Observable Inputs				Significant Unobservable Inputs
In thousands		(Level 1)				(Level 2)				(Level 3)				Total
December 31, 2019
Assets
Oil derivative contracts – current		$	—			$	8,503			$	3,433			$	11,936
Total Assets		$	—			$	8,503			$	3,433			$	11,936
Liabilities
Oil derivative contracts – current		$	—			$	(6,522	)		$	(1,824	)		$	(8,346	)
Total Liabilities		$	—			$	(6,522	)		$	(1,824	)		$	(8,346	)
December 31, 2018
Assets
Oil derivative contracts – current		$	—			$	81,621			$	11,459			$	93,080
Oil derivative contracts – long-term		—				2,030				2,165				4,195
Total Assets		$	—			$	83,651			$	13,624			$	97,275

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Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Consolidated Statements of Operations.

Level 3 Fair Value Measurements

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2019 and 2018:

		Year Ended December 31,
In thousands		2019				2018
Fair value of Level 3 instruments, beginning of year		$	13,624			$	—
Fair value adjustments on commodity derivatives		(8,205		)		13,624
Receipt on settlements of commodity derivatives		(3,810		)		—
Fair value of Level 3 instruments, end of year		$	1,609			$	13,624
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date		$	(556	)		$	13,624

We utilize an income approach to value our Level 3 three-way collars. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:

		Fair Value at 12/31/2019 (in thousands)				Valuation Technique		Unobservable Input		Volatility Range
Oil derivative contracts		$	1,609			Discounted cash flow / Black-Scholes		Volatility of Light Louisiana Sweet for settlement periods beginning after December 31, 2019		12.6% – 34.5%

Other Fair Value Measurements

The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods.  We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of our senior secured second lien notes, convertible senior notes, and senior subordinated notes are based on quoted market prices, which are considered Level 1 measurements under the fair value hierarchy.  The estimated fair value of the principal amount of our debt as of December 31, 2019 and 2018, excluding pipeline financing and capital lease obligations, was $1,833.1 million and $1,886.1 million, respectively.  We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 12. Commitments and Contingencies

Commitments

We have entered into long-term commitments to purchase CO₂ that are either non-cancelable or cancelable only upon the occurrence of specified future events.  The commitments continue for up to 9 years.  The price we will pay for CO₂ generally varies depending on the amount of CO₂ delivered and the price of oil.  Once all commitments have commenced, our annual commitment under these contracts could range from $14 million to $33 million per year, assuming a $60 per Bbl NYMEX oil price.

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We are party to long-term contracts that require us to deliver CO₂ to our industrial CO₂ customers at various contracted prices. Based upon the maximum amounts deliverable as stated in the industrial contracts, we estimate that we may be obligated to deliver up to 770 Bcf of CO₂ to these customers over the next 15 years. The maximum volume required in any given year is approximately 257 MMcf/d, which we judge to be minor given the size of our Jackson Dome proved CO₂ reserves at December 31, 2019, our current production capabilities and our projected levels of CO₂ usage for our own tertiary flooding program.

Litigation

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties.  We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

Riley Ridge Helium Supply Contract Claim

As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC (“APMTG”).  The helium supply contract provides for the delivery of a minimum contracted quantity of helium, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are capped at an aggregate of $46.0 million over the term of the contract.

As the gas processing facility has been shut-in since mid-2014 due to significant technical issues, we have not been able to supply helium under the helium supply contract. In a case filed in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, APMTG claimed multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract. The Company claimed that its contractual obligations were excused by virtue of events that fall within the force majeure provisions in the helium supply contract.

On March 11, 2019, the trial court entered a final judgment that a force majeure condition did exist, but the Company’s performance was excused by the force majeure provisions of the contract for only a 35-day period in 2014, and as a result the Company should pay APMTG liquidated damages and interest thereon for those time periods from contract commencement to the close of evidence (November 29, 2017). The Company’s position continues to be that its contractual obligations have been and continue to be excused by events that fall within the force majeure provisions of the helium supply contract, so the Company has appealed the trial court’s ruling to the Wyoming Supreme Court. Briefing for the appeal by the Company and APMTG is currently expected to be completed in late May or early June, after which oral arguments will be scheduled and heard prior to the Wyoming Supreme Court entering its judgment on the appeal. The timing and outcome of this appeal process is currently unpredictable, but at this time is anticipated to extend over the next nine to twelve months.

Absent reversal of the trial court’s ruling on appeal, the Company anticipates total liquidated damages would equal the $46.0 million aggregate cap under the helium supply contract plus $5.2 million of associated costs (through December 31, 2019), for a total of $51.2 million, which is included in “Other liabilities” in our Consolidated Balance Sheets as of December 31, 2019, and $49.4 million of which was accrued in the fourth quarter of 2018. The Company currently has a $32.8 million letter of credit posted as security in this case as part of the appeal process.

Other Contingencies

We are subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe.  In the past, settlement of these matters has not had a material adverse financial impact on us, and currently we have no material assessments for potential taxes.

We are subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry.  Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters.  Although we believe that we have complied with the various laws and regulations, administrative rulings

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and interpretations thereof, adjustments could be required as new interpretations and regulations are issued.  In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.

Note 13. Additional Balance Sheet Details

Trade and Other Receivables, Net

		December 31,
In thousands		2019				2018
Trade accounts receivable, net		$	12,630			$	11,643
Federal income tax receivable, net		2,987				9,037
Commodity derivative settlement receivables		675				2,390
Other receivables		2,026				3,900
Total		$	18,318			$	26,970

Note 14. Supplemental Cash Flow Information

Supplemental Cash Flow Information

		Year Ended December 31,
In thousands		2019				2018				2017
Supplemental cash flow information
Cash paid for interest, expensed		$	72,842			$	50,076			$	98,261
Cash paid for interest, capitalized		36,671				37,079				30,762
Cash paid for interest, treated as a reduction of debt		85,303				79,606				50,349
Cash paid for income taxes		2,361				492				450
Cash received from income tax refunds		9,820				8,280				13,323
Noncash investing and financing activities
Increase in asset retirement obligations		13,560				4,499				9,565
Increase (decrease) in liabilities for capital expenditures		(17,740		)		14,600				3,930
Conversion of convertible senior notes into common stock		—				162,004				—
Retirement of treasury stock		—				—				46,562

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(1)	Capitalized general and administrative costs that directly relate to exploration and development activities were $39.5 million, $37.2 million and $41.1 million for the years ended December 31, 2019, 2018 and 2017, respectively.

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(1)	Represents an allocation of the depletion and depreciation of our CO2 properties and pipelines associated with our tertiary oil producing activities.

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(1)

Improved recovery reflects reserve additions that result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO2 flooding.  In order to recognize proved tertiary oil reserves, we must either have an oil production response to CO2 injections or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that we can book in any given year will depend on our progress with new floods and the timing of the production response.

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(1)	Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO2 flooding.

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(1)

Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross (8/8ths) basis, of which our net revenue interest was approximately 3.8 Tcf, 4.0 Tcf and 4.1 Tcf at December 31, 2019, 2018 and 2017, respectively, and include reserves dedicated to volumetric production payments of 3.1 Bcf and 7.6 Bcf at December 31, 2018 and 2017, respectively.

(2)	Proved CO2 reserves in the Rocky Mountain region consist of our overriding royalty interest in LaBarge Field, of which our net revenue interest was approximately 1.1 Tcf, 1.2 Tcf and 1.2 Tcf at December 31, 2019, 2018 and 2017, respectively.

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