DENBURY INC - Annual Report: 2019 (Form 10-K)

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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”).

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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.

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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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(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).

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

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(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.

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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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(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.

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(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.

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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.

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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.

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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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