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Item 2. Management’s Discussion and Analysis

2021-10-29 compared with 2021-07-30 · 212 added, 192 removed, 364 unchanged (53% of the section changed)

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Please refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements.

Additionally, the following discussion includes sequential quarterly comparison to financial information presented in our Quarterly Report on Form 10-Q for the qu arter ended March 31, 2021 , filed with the SEC on April 30, 2021.

Throughout the following discussion, we explain changes between the three months ended June 30, 2021, compared with the three months ended March 31, 2021 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the six months ended June 30, 2021, compared with the same period in 2020 (“YTD 2021-over-YTD 2020”).

Additionally, the following discussion includes sequential quarterly comparison to financial information presented in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 , filed with the SEC on July 30, 2021.

Throughout the following discussion, we explain changes between the three months ended September 30, 2021, compared with the three months ended June 30, 2021 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the nine months ended September 30, 2021, compared with the same period in 2020 (“YTD 2021-over-YTD 2020”).

Overview of the Company

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Our vision is to be a premier operator of top tier assets and to sustainably grow value for all of our stakeholders.

This includes short-term operational and financial goals of generating positive cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics, and increasing the value of our capital project inventory through exploration and development optimization.

This includes short-term operational and financial goals of generating cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics, and increasing the value of our capital project inventory through exploration and development optimization.

Our long-term goal is to deliver cash flow growth that is supported by our high-quality asset base and ability to generate favorable returns.

Our investment portfolio is comprised of oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in the Maverick Basin of South Texas.

Our asset portfolio is comprised of oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in the Maverick Basin of South Texas.

We are committed to exceptional safety, health, and environmental stewardship;

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The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the development and implementation of the Company’s environmental, social and governance policies, programs and initiatives, and, together with management, reports to our Board of Directors regarding such matters.

Further demonstrating our commitment to sustainable operations, compensation for our executives and eligible employees under our long-term incentive plans, and compensation for all employees under our short-term incentive plans is calculated based on certain Company-wide performance-based metrics that include key financial, operational, and environmental, health, and safety measures.

Further demonstrating our commitment to sustainable operations, compensation for our executives and eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on certain Company-wide performance-based metrics that include key financial, operational, and environmental, health, and safety measures.

Areas of Operations

Our Midland Basin assets are comprised of approximately 80,000 net acres located in the Permian Basin in West Texas (“Midland Basin”).

In the second quarter of 2021, drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continued to focus primarily on delineating, developing, and expanding our Midland Basin position.

In the third quarter of 2021, drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continued to focus primarily on delineating and developing our Midland Basin position.

Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.

Our South Texas assets are comprised of approximately 155,000 net acres located in the Maverick Basin in Dimmit and Webb Counties, Texas (“South Texas”).

Our current operations in South Texas are focused on production from both the Eagle Ford shale formation and Austin Chalk formation and further delineation and development of the Austin Chalk formation.

For the nine months ended September 30, 2021, our operations in South Texas were focused on production from both the Eagle Ford shale formation and Austin Chalk formation, and further development of the Austin Chalk formation.

Our overlapping acreage position in the Eagle Ford shale and Austin Chalk formations includes acreage in oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.

2021 capital activity in South Texas has been, and will continue to be, concentrated on the Austin Chalk formation given the favorable economics we achieve from a higher oil and NGL product mix.

Second Quarter 2021 Overview and Outlook for the Remainder of 2021

During the second quarter of 2021, we issued $400.0 million in aggregate principal amount of our 2028 Senior Notes and we used the net proceeds to repurchase $193.1 million and $172.3 million of outstanding principal amount of our 2022 Senior Notes and 2024 Senior Notes, respectively, through the Tender Offer, and to redeem the remaining $19.3 million of 2022 Senior Notes outstanding through the 2022 Senior Notes Redemption.

We paid total consideration, excluding accrued interest, of $385.3 million, and recorded a loss on extinguishment of debt of $2.1 million for the three months ended June 30, 2021, which included $1.5 million of accelerated unamortized deferred financing costs and $600,000 of net premiums.

Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

The Pandemic remains a global health crisis, and while the United States has seen substantial improvements in public health and macroeconomic measures in recent months, and has deployed vaccinations to prevent the spread of the COVID-19 virus, stability in the markets and demand for the commodities produced by our industry have not returned to pre-Pandemic levels, and may not for some time.

The impacts of the Pandemic continue to be unpredictable and dynamic, so we are unable to reasonably estimate the period of time that related market conditions could exist or the extent to which they could continue to impact our business, results of operations, financial condition, or the timing of further recovery.

Commodity prices have improved from historic lows in 2020, however,

future case surges or outbreaks, and COVID-19 virus variants, could have further negative impacts, and as a result, may require us to adjust our business plan.

Third Quarter 2021 Overview and Outlook for the Remainder of 2021

During the third quarter of 2021, we remained committed to our goal of reducing the principal balance of our outstanding debt through cash flow generation.

For the three months ended September 30, 2021, net cash provided by operating activities exceeded net cash used in investing activities by $153.3 million, and we reduced the principal balance of our outstanding debt by $118.0 million.

We executed on this goal through strong operational performance and a diligent focus on cost management.

Additionally, we benefited from increased commodity pricing which has improved from historic lows experienced during the height of the Pandemic due to increased demand.

The Pandemic remains a global health crisis and continues to evolve, with the Delta variant becoming the predominant strain of the virus worldwide.

Despite the emergence of the Delta variant, the United States has experienced substantial improvements in financial markets and public health as a result of deployment of vaccines to prevent the spread of the COVID-19 virus.

The markets for the commodities produced by our industry strengthened in recent months, but remain subject to heightened levels of uncertainty related to the Pandemic and other geopolitical issues.

As a result, we are unable to reasonably estimate the extent that volatile market conditions could impact our business, results of operations, financial condition, or the timing of further recovery.

Although demand for the commodities produced by our industry has increased, and associated prices have improved from historic lows in 2020, with sustained gas prices reaching their highest average price since 2014, further negative financial markets and industry-specific impacts

could result from future case surges, outbreaks, COVID-19 virus variants, the potential that current vaccines may be less effective or ineffective against future COVID-19 virus variants, and the risk that large groups of the population may not receive vaccinations against COVID-19, and as a result, may require us to adjust our business plan.

For additional detail, please refer to the Risk Factors section in Part I, Item 1A of our 2020 Form 10-K .

Despite continuing impacts of the Pandemic and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our top tier Midland Basin and South Texas assets.

Despite continuing impacts of the Pandemic, geopolitical issues, and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our top tier Midland Basin and South Texas assets.

The safety of our employees, contractors, and the communities where we work remains our first priority as we continue to operate during the Pandemic.

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Our 2021 capital program remains focused on highly economic oil development projects in both our Midland Basin assets and South Texas assets.

Based on the current macroeconomic environment, we believe our assets provide strong returns and are capable of providing for growth of internally generated cash flows while allowing for flexibility of production levels, which aligns with our priorities of improving leverage metrics and maintaining strong financial flexibility.

Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund our 2021 capital program.

We believe that our high quality asset portfolio is capable of generating strong returns in the current macroeconomic environment, enabling us to grow cash flows, improve leverage metrics, and maintain strong financial flexibility.

Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our 2021 capital program.

Financial and Operational Results.

Average net daily equivalent production for the three months ended June 30, 2021, was 136.5 MBOE and increased 22 percent sequentially as the first quarter of 2021 was impacted by a significant weather event in the state of Texas that lasted for several days in February 2021, which included abnormally low temperatures and freezing conditions, and resulted in widespread power outages (“Texas Weather Event”).

Strengthening benchmark commodity prices in the second quarter of 2021 resulted in increases in realized prices, as defined below, for oil and NGLs of 16 percent and five percent, respectively, for the three months ended June 30, 2021, compared with the three months ended March 31, 2021.

The supply and demand imbalance caused by the Texas Weather Event inflated realized prices for gas in the first quarter of 2021, which resulted in a 20 percent decrease in realized prices for the three months ended June 30, 2021, compared with the three months ended March 31, 2021.

Total realized price per BOE increased eight percent for the three months ended June 30, 2021, compared with the three months ended March 31, 2021.

This increase resulted in oil, gas, and NGL production revenue of $562.6 million for the three months ended June 30, 2021, compared with $423.2 million for the three months ended March 31, 2021, which was an increase of 33 percent.

Production costs per BOE of $10.10 for the three months ended June 30, 2021, were flat compared with the three months ended March 31, 2021.

We recorded net derivative losses of $370.3 million and $344.7 million for the three months ended June 30, 2021, and March 31, 2021, respectively.

Included within these amounts are realized derivative settlement losses of $158.8 million and $107.9 million for the three months ended June 30, 2021, and March 31, 2021, respectively, resulting from increased commodity prices.

Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2021, and March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020 below for additional discussion.

Financial and operational activities during the three months ended June 30, 2021, resulted in the following:

• Net cash provided by operating activities of $296.4 million for the three months ended June 30, 2021, compared with $105.6 million for the three months ended March 31, 2021.

The sequential quarterly increase was primarily a result of changes in working capital.

• A net loss of $223.0 million, or $1.88 per diluted share, for the three months ended June 30, 2021, compared with a net loss of $251.3 million, or $2.19 per diluted share, for the three months ended March 31, 2021.

The net loss for the three months ended June 30, 2021, was primarily due to a $370.3 million net derivative loss.

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2021, and March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020 below for additional discussion regarding the components of net loss for the periods presented.

• Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended June 30, 2021, was $256.9 million, compared with $215.0 million for the three months ended March 31, 2021.

Please refer to the caption Non-GAAP

Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations of net loss and net cash provided by operating activities.

Average net daily equivalent production for the three months ended September 30, 2021, increased 14 percent sequentially to 155.8 MBOE primarily driven by a 19 percent increase in oil volumes.

These increases were the result of our focus on operational execution, strong well performance, and acceleration of capital activity in the second and third quarters of 2021.

Strengthening benchmark commodity prices in the third quarter of 2021 resulted in increased realized prices for oil, gas, and NGLs of six percent, 53 percent, and 30 percent, respectively, for the three months ended September 30, 2021, compared with the three months ended June 30, 2021.

Total realized price per BOE increased 17 percent for the three months ended September 30, 2021, compared with the three months ended June 30, 2021.

The increases in benchmark commodity prices, combined with the increase in production volumes, resulted in oil, gas, and NGL production revenue of $759.8 million for the three months ended September 30, 2021, compared with $562.6 million for the three months ended June 30, 2021, which was an increase of 35 percent.

Production costs per BOE of $9.47 for the three months ended September 30, 2021, decreased six percent compared with the three months ended June 30, 2021, primarily as a result of decreases in transportation costs per BOE and lease operating expense (“LOE”) per BOE, partially offset by increases in production taxes per BOE.

We recorded net derivative losses of $209.1 million and $370.3 million for the three months ended September 30, 2021, and June 30, 2021, respectively.

Included within these amounts are derivative settlement losses of $213.6 million and $158.8 million for the three months ended September 30, 2021, and June 30, 2021, respectively, resulting from increased benchmark commodity prices.

Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2021, and June 30, 2021, and Between the Nine Months Ended September 30, 2021, and 2020 below for additional discussion.

Financial and operational activities during the three months ended September 30, 2021, resulted in the following:

• Net cash provided by operating activities of $328.1 million for the three months ended September 30, 2021, compared with $296.4 million for the three months ended June 30, 2021.

• A cash balance of $29.8 million and no outstanding balance on the revolving credit facility as of September 30, 2021, compared with a revolving credit facility balance of $52.5 million as of June 30, 2021.

• Net income of $85.6 million, or $0.69 per diluted share, for the three months ended September 30, 2021, compared with a net loss of $223.0 million, or $1.88 per diluted share, for the three months ended June 30, 2021.

Net income for the three months ended September 30, 2021, was primarily a result of increased production and pricing.

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2021, and June 30, 2021, and Between the Nine Months Ended September 30, 2021, and 2020 below for additional discussion regarding the components of net income (loss) for the periods presented.

• Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended September 30, 2021, was $346.7 million, compared with $256.9 million for the three months ended June 30, 2021.

Please refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income (loss) and net cash provided by operating activities.

Operational Activities.

In our Midland Basin program, we operated three drilling rigs and averaged three completion crews during the second quarter of 2021.

We drilled 14 gross (11 net) wells and completed 44 gross (40 net) wells during the second quarter of 2021, and production volumes increased sequentially by 22 percent to 8.3 MMBOE compared with the three months ended March 31, 2021.

Costs incurred in our Midland Basin program during the three months ended June 30, 2021, totaled $155.9 million, or 69 percent of our total costs incurred for the period.

We anticipate operating between two and three drilling rigs and between one and two completion crews at times during the remainder of 2021, focused primarily on delineating and developing the Spraberry and Wolfcamp formations within our RockStar and Sweetie Peck positions in the Midland Basin.

In our South Texas program, we operated two drilling rigs and one completion crew at times during the second quarter of 2021.

We drilled 11 gross (11 net) wells and completed five gross (five net) wells during the second quarter of 2021, and production volumes increased sequentially by 28 percent to 4.1 MMBOE compared with the three months ended March 31, 2021.

Costs incurred in our South Texas program during the three months ended June 30, 2021, totaled $59.5 million, or 26 percent of our total costs incurred for the period.

We anticipate operating between one and two drilling rigs and one completion crew during the remainder of 2021, focused primarily on delineating and developing the Austin Chalk formation.

The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the three and six months ended June 30, 2021:

In our Midland Basin program, we operated an average of three drilling rigs and averaged one completion crew during the third quarter of 2021.

We drilled 17 gross (14 net) wells and completed 30 gross (24 net) wells during the third quarter of 2021, and production volumes increased sequentially by 18 percent to 9.8 MMBOE.

Costs incurred in our Midland Basin program during the three months ended September 30, 2021, totaled $101.5 million, or 59 percent of our total costs incurred for the period.

We anticipate operating two drilling rigs and one completion crew at times during the remainder of 2021, focused primarily on developing the Spraberry and Wolfcamp formations within our RockStar and Sweetie Peck positions in the Midland Basin.

In our South Texas program, we operated an average of two drilling rigs and averaged one completion crew during the third quarter of 2021.

We drilled 10 gross (10 net) wells and completed 11 gross (11 net) wells during the third quarter of 2021, and production volumes increased sequentially by 10 percent to 4.5 MMBOE.

Costs incurred in our South Texas program during the three months ended September 30, 2021, totaled $59.3 million, or 34 percent of our total costs incurred for the period.

We anticipate operating one drilling rig and one completion crew during the remainder of 2021, focused primarily on developing the Austin Chalk formation.

Midland Basin South Texas (2)

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Wells drilled but not completed at June 30, 2021 36 29 36 36 72 65

Wells drilled 17 14 10 10 27 24

Wells completed (30) (24) (11) (11) (41) (35)

— (1) — — — (1)

Wells drilled but not completed at September 30, 2021 23 18 35 35 58 53

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(1) Includes adjustments related to normal business activities, including working interest changes for existing drilled but not completed wells.

Working interest changes can result from divestitures, joint development agreements, farmouts, and other activities.

Working interest changes can result from divestitures, joint development agreements, farm-outs, and other activities.

(2) The South Texas drilled but not completed well count as of each period end presented above includes 13 gross (13 net) wells that are not included in our five-year development plan, 12 of which are in the Eagle Ford shale.

Costs Incurred.

Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $224.6 million and $417.2 million for the three and six months ended June 30, 2021, respectively, and were primarily incurred in our Midland Basin and South Texas programs as further detailed in Operational Activities above.

Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $172.5 million and $589.7 million for the three and nine months ended September 30, 2021, respectively, and were primarily incurred in our Midland Basin and South Texas programs as further detailed in Operational Activities above.

Production Results.

The table below presents our production by product type for each of our areas of operation for the sequential quarterly periods and the YTD 2021-over-YTD 2020 periods:

For the Three Months Ended For the Six Months Ended

June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020

For the Three Months Ended For the Nine Months Ended

September 30, 2021 June 30, 2021 September 30, 2021 September 30, 2020

Midland Basin Production:

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Amounts may not calculate due to rounding.

Oil, Gas, and NGL Prices

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While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the three months ended June 30, 2021, March 31, 2021, and June 30, 2020:

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the three months ended September 30, 2021, June 30, 2021, and September 30, 2020:

For the Three Months Ended

June 30, 2021 March 31, 2021 June 30, 2020

September 30, 2021 June 30, 2021 September 30, 2020

Oil (per Bbl):

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Realized prices reflect our actual product mix.

Given the dynamic nature of the Pandemic, we expect future benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing of any further recovery or future infection rate surges or outbreaks.

Given the dynamic nature of the Pandemic, we expect future benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing or likelihood of any future potential negative impacts of the Pandemic such as infection rate surges or outbreaks.

In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in various regions of the world as well as the relative strength of the United States dollar compared to other currencies.

Our realized prices at local sales points may also be affected by infrastructure capacity in the area of our operations and beyond.

Please refer to Second Quarter 2021 Overview and Outlook for the Remainder of 2021 above for additional discussion of factors impacting pricing.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of July 21, 2021, and June 30, 2021:

As of July 21, 2021 As of June 30, 2021

Please refer to Third Quarter 2021 Overview and Outlook for the Remainder of 2021 above for additional discussion of factors impacting pricing.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of October 21, 2021, and September 30, 2021:

As of October 21, 2021 As of September 30, 2021

NYMEX WTI oil (per Bbl) $ 77.90 $ 72.54

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Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information for the three months ended June 30, 2021, and the preceding three quarters.

The tables below provide information regarding selected production and financial information for the three months ended September 30, 2021, and the preceding three quarters.

For the Three Months Ended

June 30, March 31, December 31, September 30,

September 30, June 30, March 31, December 31,

2021 2021 2021 2020

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General and administrative $ 25.5 $ 24.6 $ 24.7 $ 20.0

Net loss $ (223.0) $ (251.3) $ (165.2) $ (98.3)

Net income (loss) $ 85.6 $ (223.0) $ (251.3) $ (165.2)

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For the Three Months Ended

June 30, March 31, December 31, September 30,

September 30, June 30, March 31, December 31,

2021 2021 2021 2020

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Overview of Selected Production and Financial Information, Including Trends

For the Three Months Ended Amount Change Between Periods Percent Change Between Periods For the Six Months Ended Amount Change Between Periods Percent Change Between Periods

June 30, March 31, June 30, June 30,

For the Three Months Ended Amount Change Between Periods Percent Change Between Periods For the Nine Months Ended Amount Change Between Periods Percent Change Between Periods

September 30, June 30, September 30, September 30,

2021 2021 2021 2020

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Diluted weighted-average common shares outstanding 123,851 118,357 5,494 5 % 118,224 113,462 4,762 4 %

Basic net loss per common share $ (1.88) $ (2.19) $ 0.31 14 % $ (4.07) $ (4.43) $ 0.36 8 %

Diluted net loss per common share $ (1.88) $ (2.19) $ 0.31 14 % $ (4.07) $ (4.43) $ 0.36 8 %

Basic net income (loss) per common share $ 0.70 $ (1.88) $ 2.58 137 % $ (3.29) $ (5.28) $ 1.99 38 %

Diluted net income (loss) per common share $ 0.69 $ (1.88) $ 2.57 137 % $ (3.29) $ (5.28) $ 1.99 38 %

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(1) Amounts and percentage changes may not calculate due to rounding.

(2) Derivative settlements for the three months ended June 30, 2021, and for the six months ended June 30, 2021, and 2020, are included within the net derivative (gain) loss line item in the accompanying statements of operations.

(2) Derivative settlements for the three months ended September 30, 2021, and for the nine months ended September 30, 2021, and 2020, are included within the net derivative (gain) loss line item in the accompanying statements of operations.

(3) Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.

Average net daily equivalent production for the three months ended June 30, 2021, increased 22 percent sequentially and decreased four percent YTD 2021-over-YTD 2020.

The sequential quarterly increase is primarily related to the Texas Weather Event that caused temporary impacts to production in the first quarter of 2021.

Average net daily equivalent production for the three months ended September 30, 2021, increased 14 percent sequentially as a result of increases of 16 percent and nine percent in average net daily equivalent production volumes from our Midland Basin assets and our South Texas assets, respectively.

These increases were the result of our focus on operational execution, strong well performance, and acceleration of capital activity in the second and third quarters of 2021.

Average net daily equivalent production for the nine months ended September 30, 2021, increased five percent compared with the same period in 2020, as a result of an increase of 16 percent in average net daily equivalent production volumes from our Midland Basin assets, resulting from an increased number of completions and strong well performance YTD 2021-over-YTD 2020.

We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.

Our realized price on a per BOE basis for the three months ended June 30, 2021, increased $3.17 sequentially as a result of strengthening benchmark commodity prices.

Our realized price on a per BOE basis increased $7.74 sequentially as a result of strengthening benchmark commodity prices.

The positive impact on oil, gas, and NGL production revenues resulting from the sequential quarterly realized price increase was partially offset by an increase in the loss on the settlement of our derivative contracts of $2.12 per BOE.

Our realized price on a per BOE basis increased $21.62 YTD 2021-over-YTD 2020, primarily as a result of strengthening benchmark commodity prices as benchmark commodity prices during the six months ended June 30, 2020, fell to historic lows as a result of the impacts of the Pandemic.

Further contributing to the YTD 2021-over-YTD 2020 increase were increased gas prices during the first quarter of 2021 resulting from the supply and demand imbalance caused by the Texas Weather Event.

The positive impact on oil, gas, and NGL production revenues resulting from the YTD 2021-over-YTD 2020 realized price increase was mostly offset by a 229% change in the settlement of our derivative contracts which were a loss of $11.87 per BOE for the six months ended June 30, 2021, compared to a gain of $9.17 per BOE for the same period in 2020.

Lease operating expense (“LOE”) on a per BOE basis for the three months ended June 30, 2021, remained flat sequentially, and increased 14 percent YTD 2021-over-YTD 2020.

The YTD 2021-over-YTD 2020 increase was driven by the increased percentage of oil in our total product mix, which has higher lifting costs per BOE, and by a total net equivalent production volume decrease of five percent.

Our realized price on a per BOE basis increased $24.51 YTD 2021-over-YTD 2020, primarily as a result of higher benchmark commodity prices, which have improved from historic lows experienced during 2020 as a result of the impacts of the Pandemic and other macroeconomic events.

Further contributing to the YTD 2021-over-YTD 2020 increase were increased gas prices during the first quarter of 2021 resulting from a supply and demand imbalance caused by a significant weather event in the state of Texas that lasted for several days in February 2021, which included abnormally low temperatures and freezing conditions, and resulted in widespread power outages.

The positive impact on oil, gas, and NGL production revenues resulting from the YTD 2021-over-YTD 2020 realized price increase was substantially offset by a 260% change in the settlement of our derivative contracts which were a loss of $13.05 per BOE for the nine months ended September 30, 2021, compared to a gain of $8.14 per BOE for the same period in 2020.

LOE on a per BOE basis decreased nine percent sequentially, primarily as a result of production volume increases outpacing increases in total LOE due to operational efficiencies and cost savings associated with produced water recycling.

LOE on a per BOE basis increased 13 percent YTD 2021-over-YTD 2020, driven by the increased percentage of oil in our total product mix, which has higher lifting costs per BOE, and increased workover expense.

For the full year 2021, we expect LOE on a per BOE basis to increase, compared with 2020, due to higher oil production and increased workover expense.

We anticipate volatility in LOE on a per BOE basis as a result of changes in total production, changes in our overall production mix, timing of workover projects, and industry activity, all of which impact total LOE.

Transportation costs on a per BOE basis for the three months ended June 30, 2021 increased slightly sequentially, and decreased four percent YTD 2021-over-YTD 2020 as a result of a 19 percent decrease in production volumes from our South Texas assets, which incur the majority of our transportation costs.

We expect total transportation costs to fluctuate relative to changes in production from our South Texas assets.

On a per BOE basis, we expect transportation costs to decrease for the full year 2021, compared with 2020, as production from our Midland Basin assets, which is sold at or near the wellhead and incurs minimal transportation costs, comprises a larger portion of our total production.

Transportation costs on a per BOE basis decreased 20 percent sequentially and decreased 12 percent YTD 2021-over-YTD 2020.

The sequential quarterly decrease was the result of an 18 percent increase in production volumes from our Midland Basin assets, which are sold at or near the wellhead and incur minimal transportation costs.

Additionally, during the third quarter of 2021, we benefited from cost reductions on one of our transportation contracts.

The YTD 2021-over-YTD 2020 decrease was the result of a 13 percent decrease in production volumes from our South Texas assets, which incur the majority of our transportation costs.

We expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets.

On a per BOE basis, we expect transportation costs to decrease for the full year 2021, compared with 2020, as we expect production from our Midland Basin assets to continue to comprise a larger portion of our total production.

Further, we anticipate natural declines in production from our Eagle Ford shale wells in South Texas, which incur higher transportation costs on a per BOE basis, and we intend to focus on new wells with higher liquids content in the Austin Chalk, which have lower transportation costs on a per BOE basis.

In addition, we expect to benefit from certain transportation contract cost reductions that are expected to further reduce our transportation expense per BOE during 2021.

Production taxes on a per BOE basis for the three months ended June 30, 2021, increased five percent sequentially, and increased 121 percent YTD 2021-over-YTD 2020, primarily driven by increases in realized prices.

Our overall production tax rate was 4.5 percent for each of the three and six months ended June 30, 2021, compared with 4.6 percent for the three months ended March 31, 2021, and 4.0 percent for the six months ended June 30, 2020.

The YTD 2021-over-YTD 2020 increase in the production tax rate was primarily driven by increases in realized prices and increased production from our Midland Basin assets.

In addition, one of our transportation contracts in South Texas has an embedded cost reduction that took effect during the third quarter of 2021 and, as a result, we expect a decrease in transportation costs on a per BOE basis for the full-year 2021 compared with 2020.

Production tax expense on a per BOE basis increased 23 percent sequentially, and increased 132 percent YTD 2021-over-YTD 2020, primarily driven by increases in realized prices and an increase in production from our Midland Basin assets.

Our overall production tax rate was 4.7 percent and 4.5 percent for the three months ended September 30, 2021, and June 30, 2021, respectively, and 4.6 percent and 4.1 percent for the nine months ended September 30, 2021, and 2020, respectively.

We expect our total production tax expense to increase in 2021, compared with 2020, as we expect oil, gas, and NGL production revenue to increase due to increased pricing.

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Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax that we recognize.

Ad valorem tax expense on a per BOE basis for the three months ended June 30, 2021, decreased 13 percent sequentially, and increased 14 percent YTD 2021-over-YTD 2020.

Ad valorem tax expense on a per BOE basis decreased 16 percent sequentially and increased seven percent YTD 2021-over-YTD 2020.

The sequential quarterly decrease was a result of increased net equivalent production volumes.

The YTD 2021-over-YTD 2020 increase was primarily a result of changes to the expected value assessments of our producing properties.

We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties change.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis remained flat sequentially, and decreased six percent YTD 2021-over-YTD 2020.

The YTD 2021-over-YTD 2020 decrease was primarily driven by the reduction in the depletable cost basis of our South Texas proved oil and gas properties as a result of proved property impairments recognized during the first quarter of 2020.

We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis decreased 14 percent sequentially as a result of strong well performance, increased commodity pricing, and lower well costs in our Midland Basin assets.

DD&A expense on a per BOE basis decreased eight percent YTD 2021-over-YTD 2020 due to the aforementioned reasons as well as the reduction in the depletable cost basis of our South Texas proved oil and gas properties as a result of proved property impairments recognized during the first quarter of 2020.

Our DD&A rate fluctuates as a result of impairments, divestiture activity, carrying cost funding and sharing arrangements with third parties, changes in our production mix, and changes in our total estimated proved reserve volumes.

For the full year 2021, we expect DD&A per BOE and DD&A expense on an absolute basis to

decrease compared with 2020, primarily as a result of increased activity in our Austin Chalk program compared with 2020, as these assets have a lower DD&A rate than our Midland Basin assets.

General and administrative (“G&A”) expense on a per BOE basis decreased 20 percent sequentially, and decreased five percent YTD 2021-over-YTD 2020.

The sequential quarterly decrease was primarily the result of increased production volumes during the three months ended June 30, 2021, and the YTD 2021-over-YTD 2020 decrease was primarily the result of actions taken to reduce costs in response to the Pandemic.

For the full year 2021, we expect G&A expense to be relatively flat, in total and on a per BOE basis, compared with 2020.

Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2021, and March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020

For the full year 2021, we expect DD&A expense per BOE and DD&A expense on an absolute basis to decrease compared with 2020, primarily as a result of increased commodity pricing, strong well performance, lower well costs, and increased activity in our Austin Chalk program compared with 2020, as these assets have a lower DD&A rate than our Midland Basin assets.

General and administrative (“G&A”) expense on a per BOE basis decreased 10 percent both sequentially and YTD 2021-over-YTD 2020.

These decreases were primarily the result of increased production volumes, and the YTD 2021-over-YTD 2020 decrease was partially driven by actions taken to reduce costs in response to the Pandemic.

Certain components of G&A expense, and G&A expense on a per BOE basis, are impacted by the Company’s full year performance against performance targets established at the beginning of the year.

For the full year 2021, we expect G&A expense to be relatively flat on an absolute basis, however could trend higher based on the impacts that increased commodity pricing and strong operational performance are having on the Company’s performance metrics through September 30, 2021.

Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2021, and June 30, 2021, and Between the Nine Months Ended September 30, 2021, and 2020

Net equivalent production, production revenue, and production expense

Sequential Quarterly Changes.

The following table presents the changes in our net equivalent production, production revenue, and production expense, by area, between the three months ended June 30, 2021, and March 31, 2021:

The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the three months ended September 30, 2021, and June 30, 2021:

Net Equivalent Production

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Increase Production Expense

Increase (Decrease)

(MBOE per day) (in millions) (in millions)

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Amounts may not calculate due to rounding.

Average net daily equivalent production volumes increased 22 percent driven by increases of 26 percent and 20 percent in average net daily equivalent production volumes from our South Texas and Midland Basin assets, respectively.

These increases were primarily related to the Texas Weather Event, which caused temporary impacts to production in the first quarter of 2021.

Realized prices for oil and NGLs increased 16 percent and five percent, respectively, and decreased 20 percent for gas.

As a result of increases in benchmark commodity prices for oil and NGLs during the second quarter of 2021, oil, gas, and NGL production revenue increased 33 percent.

Total production expense increased 24 percent as a result of increased average net daily equivalent production volumes and realized prices.

Average net daily equivalent production volumes increased 14 percent consisting of increases of 16 percent and nine percent in average net daily equivalent production volumes from our Midland Basin and South Texas assets, respectively.

Realized prices for oil, gas, and NGLs increased six percent, 53 percent, and 30 percent, respectively.

During the third quarter of 2021, as a result of increases in benchmark commodity prices for oil, gas, and NGLs and the increase in production volumes noted above, oil, gas, and NGL production revenue increased 35 percent.

Total production expense increased eight percent as a result of increased production taxes resulting from higher oil, gas, and NGL revenues.

YTD 2021-over-YTD 2020.

The following table presents the changes in our net equivalent production, production revenue, and production expense, by area, between the six months ended June 30, 2021, and 2020:

The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the nine months ended September 30, 2021, and 2020:

Net Equivalent Production

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Increase Production Expense

Increase (Decrease)

(MBOE per day) (in millions) (in millions)

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Amounts may not calculate due to rounding.

Average net daily equivalent production volumes decreased four percent, driven by a decrease of 19 percent in average net daily equivalent production volumes from our South Texas assets, partially offset by an increase of five percent in average net daily equivalent production volumes from our Midland Basin assets.

These changes were primarily the result of higher capital allocations to the Midland Basin in prior years.

Average net daily equivalent production volumes increased five percent consisting of an increase of 16 percent in average net daily equivalent production volumes from our Midland Basin assets, partially offset by a decrease of 13 percent in average net daily equivalent production volumes from our South Texas assets.

These changes were primarily the result of higher capital allocations to

the Midland Basin in prior years.

Realized prices for oil, gas, and NGLs increased 80 percent, 167 percent, and 143 percent, respectively.

As a result of increases in benchmark commodity prices, during the first half of 2021, oil, gas, and NGL production revenue increased 88 percent.

Total production expense increased 13 percent, primarily as a result of increased production taxes.

As a result of increases in benchmark commodity prices, oil, gas, and NGL production revenue increased 117 percent.

Total production expense increased 23 percent, primarily as a result of increased production taxes and LOE.

Please refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion

For the Three Months Ended For the Six Months Ended

June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020

For the Three Months Ended For the Nine Months Ended

September 30, 2021 June 30, 2021 September 30, 2021 September 30, 2020

(in millions)

Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 202.7 $ 204.7 $ 574.4 $ 596.1

DD&A expense for the three months ended June 30, 2021, increased 23 percent sequentially, and decreased 10 percent YTD 2021-over-YTD 2020.

The sequential quarterly increase was primarily driven by an increase in total net equivalent production volumes of 24 percent.

The YTD 2021-over-YTD 2020 decrease was driven by both a decrease in production volumes of five percent and the reduction in the depletable cost basis of our South Texas proved oil and gas properties as a result of proved property impairments recognized during the first quarter of 2020.

DD&A expense remained flat sequentially and decreased four percent YTD 2021-over-YTD 2020.

The YTD 2021-over-YTD 2020 decrease was driven by strong well performance, increased commodity pricing, lower well costs related to our Midland Basin assets, and the reduction in the depletable cost basis of our South Texas proved oil and gas properties as a result of proved property impairments recognized during the first quarter of 2020.

Please refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion of DD&A expense on a per BOE basis.

For the Three Months Ended For the Six Months Ended

June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020

For the Three Months Ended For the Nine Months Ended

September 30, 2021 June 30, 2021 September 30, 2021 September 30, 2020

(in millions)

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Total $ 8.7 $ 8.7 $ 26.7 $ 29.7

Exploration expense for the three months ended June 30, 2021, decreased seven percent sequentially, and decreased 15 percent YTD 2021-over-YTD 2020, primarily as a result of decreases in overhead and other expenses.

Exploration expense is impacted by actual geological and geophysical studies we perform within an exploratory area and the potential for exploratory dry hole expense.

For the Three Months Ended For the Six Months Ended

June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020

Exploration expense remained flat sequentially and decreased 10 percent YTD 2021-over-YTD 2020.

The YTD 2021-over-YTD 2020 decrease was primarily a result of decreases in overhead and other expenses.

Exploration expense is impacted by actual geological and geophysical studies we perform within an exploratory area and unsuccessful exploration activities, if any.

For the Three Months Ended For the Nine Months Ended

September 30, 2021 June 30, 2021 September 30, 2021 September 30, 2020

(in millions)

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Total $ 8.8 $ 8.8 $ 26.3 $ 1,007.3

__________________________________________

Amounts may not calculate due to rounding.

There were no proved oil and gas property impairments for the three and six months ended June 30, 2021.

During the six months ended June 30, 2020, we recorded impairment expense related to our South Texas proved oil and gas properties and related support facilities as a result of the decrease in commodity price forecasts at the end of the first quarter of 2020, specifically decreases in oil and NGL prices.

There were no proved oil and gas property impairments for the three and nine months ended September 30, 2021.

During the nine months ended September 30, 2020, we recorded impairment expense related to our South Texas proved oil and gas properties and related support facilities as a result of the decrease in commodity price forecasts at the end of the first quarter of 2020, specifically decreases in oil and NGL prices.

Unproved property abandonments and impairments recorded during each period presented above related to actual and anticipated lease expirations, as well as actual and anticipated losses of acreage due to title defects, changes in development plans, and other inherent acreage risks.

We expect proved property impairments to occur more frequently in periods of declining or depressed commodity prices, and that the frequency of unproved property abandonments and impairments will fluctuate with the timing of lease expirations or defects, and changing economics associated with decreases in commodity prices.

and changing economics associated with decreases in commodity prices.

Additionally, changes in drilling plans, unsuccessful exploration activities, and downward engineering revisions may result in proved and unproved property impairments.

Future impairments of proved and unproved properties are difficult to predict;

however, based on our commodity price assumptions as of July 21, 2021, we do not expect any material property impairments in the third quarter of 2021 resulting from commodity price impacts.

however, based on our commodity price assumptions as of October 21, 2021, we do not expect any material property impairments in the fourth quarter of 2021 resulting from commodity price impacts.

Please refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion of impairment expense.

General and administrative

For the Three Months Ended For the Six Months Ended

June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020

For the Three Months Ended For the Nine Months Ended

September 30, 2021 June 30, 2021 September 30, 2021 September 30, 2020

(in millions)

General and administrative $ 25.5 $ 24.6 $ 74.9 $ 79.1

G&A expense remained flat sequentially, and decreased 10 percent YTD 2021-over-YTD 2020, primarily as a result of actions taken to reduce costs in response to the Pandemic.

G&A expense increased four percent sequentially as a result of changes in the fair value of certain awards made under our long-term equity compensation program, and decreased five percent YTD 2021-over-YTD 2020, primarily as a result of actions taken to reduce costs in response to the Pandemic.

Please refer to the section Overview of Selected Production and Financial Information, Including Trends above for additional discussion of G&A expense in total and on a per BOE basis.

Net derivative (gain) loss

For the Three Months Ended For the Six Months Ended

June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020

For the Three Months Ended For the Nine Months Ended

September 30, 2021 June 30, 2021 September 30, 2021 September 30, 2020

(in millions)

Net derivative (gain) loss $ 209.1 $ 370.3 $ 924.2 $ (314.3)

We recognized a derivative loss of $370.3 million for the three months ended June 30, 2021.

The loss was primarily driven by a $211.5 million downward mark-to-market adjustment due to strengthening commodity prices during the second quarter of 2021.

Additionally, we recognized losses on the settlement of derivative contracts of $158.8 million during the three months ended June 30, 2021.

We recognized a derivative loss of $344.7 million for the three months ended March 31, 2021.

The loss was primarily driven by a $236.8 million downward mark-to-market adjustment due to strengthening commodity prices during the first three months of 2021.

Additionally, we recognized losses on the settlement of derivative contracts of $107.9 million during the three months ended March 31, 2021.

We recognized a derivative loss of $715.0 million for the six months ended June 30, 2021.

For contracts that settled during the first half of 2021, the fair value was a net liability of $76.1 million at December 31, 2020, and net cash settlements totaled $266.7 million, resulting in a $190.6 million loss.

We recorded a $524.4 million mark-to-market loss on unsettled contracts as of June 30, 2021 resulting from strengthening commodity prices during the first half of 2021.

We recognized a derivative gain of $378.1 million for the six months ended June 30, 2020, driven by $216.0 million of gains recognized on the settlement of derivative contracts and a $162.2 million upward mark-to-market adjustment resulting from oil price fluctuations during the first half of the year.

Net derivative (gain) loss is a result of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying our derivative contracts outstanding and the monthly cash settlements on settled derivative positions during the period.

The net derivative losses for the three and nine months ended September 30, 2021, and the three months ended June 30, 2021, resulted from increases in benchmark commodity prices during 2021.

The net derivative gain for the nine months ended September 30, 2020, was the result of decreases in benchmark commodity prices during 2020.

Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.

Other operating expense, net

For the Three Months Ended For the Nine Months Ended

September 30, 2021 June 30, 2021 September 30, 2021 September 30, 2020

(in millions)

Other operating expense, net $ 43.4 $ 1.9 $ 44.7 $ 10.2

Other operating expense, net, increased both sequentially and YTD 2021-over-YTD 2020 as a result of legal settlements recorded during the third quarter of 2021, including the settlement of the SPM NAM LLC et al.

case discussed in Legal Proceedings in Part II, Item 1 of this report.

We do not expect material charges to other operating expenses for the remainder of 2021.

Interest expense

For the Three Months Ended For the Six Months Ended

June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020

For the Three Months Ended For the Nine Months Ended

September 30, 2021 June 30, 2021 September 30, 2021 September 30, 2020

(in millions)

Interest expense $ 40.9 $ 39.5 $ 120.3 $ 123.4

Interest expense remained flat sequentially and YTD 2021-over-YTD 2020.

We expect interest expense related to our Senior Notes to decrease slightly for 2021 compared with 2020 primarily as a result of the decreased principal amount outstanding on our Senior Notes resulting from the Exchange Offers executed in the second quarter of 2020.

Interest expense increased three percent sequentially and decreased three percent YTD 2021-over-YTD 2020.

We expect interest expense related to our Senior Notes to decrease slightly for 2021 compared with 2020 primarily as a result of the decreased

principal amount outstanding on our Senior Notes resulting from the Exchange Offers completed in the second quarter of 2020, and the retirement of our remaining 2021 Senior Secured Convertible Notes which matured on July 1, 2021.

Total interest expense is impacted by and can vary based on the timing and amount of borrowings under our revolving credit facility.

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Gain (loss) on extinguishment of debt

For the Three Months Ended For the Six Months Ended

June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020

For the Three Months Ended For the Nine Months Ended

September 30, 2021 June 30, 2021 September 30, 2021 September 30, 2020

(in millions)

Gain (loss) on extinguishment of debt $ — $ (2.1) $ (2.1) $ 264.5

The Tender Offer and 2022 Senior Notes Redemption executed during the second quarter of 2021 resulted in a net loss on extinguishment of debt of $2.1 million, which included $1.5 million of accelerated unamortized deferred financing costs and $600,000 of net premiums paid.

The Exchange Offers executed during the second quarter of 2020 resulted in a net gain on extinguishment of debt of $227.3 million, which was primarily comprised of the partial principal redemption of Old Notes and the debt discount associated with the issuance of the 2025 Senior Secured Notes.

During the three months ended March 31, 2020, we recorded a $12.2 million net gain on the early extinguishment of a portion of our 2022 Senior Notes, which included discounts realized upon repurchase of $12.4 million partially offset by $235,000 of accelerated unamortized deferred financing costs.

The Tender Offer and 2022 Senior Notes Redemption completed during the second quarter of 2021 resulted in a net loss on extinguishment of debt of $2.1 million, which included $1.5 million of accelerated unamortized deferred financing costs and $0.6 million of net premiums paid during the nine months ended September 30, 2021.

During the nine months ended September 30, 2020, we recorded a net gain on extinguishment of debt related to the Exchange Offers of $227.3 million, which was primarily comprised of the partial principal redemption of Old Notes and the debt discount associated with the issuance of the 2025 Senior Secured Notes.

Also during the nine months ended September 30, 2020, we recorded net gains on the early extinguishment of portions of our 2022 Senior Notes and 2024 Senior Notes of $24.4 million and $12.9 million, respectively.

Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion of these transactions.

Income tax (expense) benefit

For the Three Months Ended For the Six Months Ended

June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020

Income tax benefit

For the Three Months Ended For the Nine Months Ended

September 30, 2021 June 30, 2021 September 30, 2021 September 30, 2020

(in millions, except tax rate)

Income tax (expense) benefit $ 0.2 $ (0.1) $ 0.1 $ 135.7

Income tax benefit $ — $ 0.2 $ 0.1 $ 158.7

Effective tax rate — % 0.1 % — % 20.9 %

The effective tax benefit rate remained flat sequentially.

The decrease in the effective tax benefit rate for the six months ended June 30, 2021, compared with the same period in 2020, was primarily due to the effects of forecasted income for the year ended December 31, 2021, compared to forecasted loss at June 30, 2020, and the correlative effect on the valuation allowance balance in each period.

The decrease in the effective tax benefit rate for the nine months ended September 30, 2021, compared with the same period in 2020, was primarily due to the effects of forecasted income for the year ended December 31, 2021, compared to forecasted loss at September 30, 2020, and the correlative effect on the valuation allowance balance in each period.

For each of the comparable periods, the tax rates reflect the proportional effects of excess tax deficiencies from stock-based compensation awards, and limits on expensing of certain covered individual’s compensation.

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Sources of Cash

We expect our 2021 capital program to be funded by cash flows from operations.

For the nine months ended September 30, 2021, cash flow from operating activities was sufficient to fund our capital program and we expect that to continue for the remainder of 2021.

Although we expect cash flows from operations to be sufficient to fund our expected 2021 capital program, we may also use borrowings under our revolving credit facility or may elect to raise funds through new debt or equity offerings or from other sources of financing.

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Additionally, we may enter into cost carrying and sharing arrangements with third parties for certain exploration or development programs.

All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, fluctuations in commodity prices, operating costs, tax law changes, and volumes produced, all of which affect us and our industry.

All of our sources of liquidity can be

affected by the general conditions of the broader economy, force majeure events, fluctuations in commodity prices, operating costs, tax law changes, and volumes produced, all of which affect us and our industry.

Our credit ratings impact the availability of and cost for us to borrow additional funds.

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Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, and a borrowing base and aggregate lender commitments of $1.1 billion.

As of September 30, 2021, the remaining available borrowing capacity under our Credit Agreement provided $1.1 billion in liquidity.

The borrowing base under the Credit Agreement is subject to regular, semi-annual redetermination, and considers the value of both our (a) proved oil and gas properties reflected in the most recent reserve report provided to our lenders under the Credit Agreement;

and (b) commodity derivative contracts, each as determined by our lender group.

During March 2021, as a result of the regular, semi-annual redetermination, both the borrowing base and aggregate lender commitments were reaffirmed at the amounts noted above.

The next scheduled borrowing base redetermination date is October 1, 2021.

As of June 30, 2021, the remaining available borrowing capacity under our Credit Agreement provided $1.0 billion in liquidity.

Subsequent to September 30, 2021, the fall semi-annual borrowing base redetermination was completed, which reaffirmed both our borrowing base and aggregate lender commitments at $1.1 billion.

The next scheduled borrowing base redetermination date is April 1, 2022.

Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities, all as provided for in the Credit Agreement.

No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement.

Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under our Credit Agreement as of July 21, 2021, June 30, 2021, and December 31, 2020.

Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under our Credit Agreement as of October 21, 2021, September 30, 2021, and December 31, 2020.

We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as set forth in the Credit Agreement.

We were in compliance with all financial and non-financial covenants as of June 30, 2021, and through the filing of this report.

We were in compliance with all financial and non-financial covenants as of September 30, 2021, and through the filing of this report.

Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

Our daily weighted-average revolving credit facility debt balance was $141.5 million and $134.2 million for the three months ended June 30, 2021, and March 31, 2021, respectively, and $137.9 million and $113.0 million for the six months ended June 30, 2021, and 2020, respectively.

As of September 30, 2021, we had a zero balance on our revolving credit facility.

Our daily weighted-average revolving credit facility debt balance was $128.2 million and $141.5 million for the three months ended September 30, 2021, and June 30, 2021, respectively, and $134.6 million and $142.2 million for the nine months ended September 30, 2021, and 2020, respectively.

Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, repayment of scheduled debt maturities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility.

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The following table details our weighted-average interest rates and our weighted-average borrowing rates for the periods presented:

For the Three Months Ended For the Six Months Ended

June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020

For the Three Months Ended For the Nine Months Ended

September 30, 2021 June 30, 2021 September 30, 2021 September 30, 2020

Weighted-average interest rate 7.7 % 7.6 % 7.7 % 6.8 %

Weighted-average borrowing rate 6.9 % 6.7 % 6.7 % 6.0 %

Our weighted-average interest rates and weighted-average borrowing rates are impacted by the timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility.

Our weighted-average interest rate and our weighted-average borrowing rate remained flat sequentially, and increased YTD 2021-over-YTD 2020.

The YTD 2021-over-YTD 2020 increase was primarily a result of the higher interest rate on our 2025 Senior Secured Notes issued during the second quarter of 2020.

Our weighted-average interest rate and weighted-average borrowing rate are impacted by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility.

Additionally, our weighted-average interest rates are impacted by the fees paid on the unused portion of our aggregate lender commitments.

For the three months ended June 30, 2021, our weighted-average interest rate and our weighted-average borrowing rate remained flat sequentially, and increased YTD 2021-over-YTD 2020, primarily as a result of the higher interest rate on our 2025 Senior Secured Notes issued during the second

quarter of 2020.

The rates disclosed in the above table do not reflect amounts associated with the repurchase or redemption of Senior Notes, such as the acceleration of unamortized deferred financing costs, as these amounts are netted against the associated gain or loss on extinguishment of debt.

The 2021 Senior Secured Convertible Notes were retired upon maturity on July 1, 2021.

After this date, the weighted-average interest rate is no longer impacted by the non-cash amortization of deferred financing costs or the non-cash amortization of the discount related to the 2021 Senior Secured Convertible Notes.

We use cash for the development, exploration, and acquisition of oil and gas properties and for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest.

Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources.

During the six months ended June 30, 2021, we spent approximately $370.2 million on capital expenditures.

This amount differs from the costs incurred amount of $417.2 million for the six months ended June 30, 2021, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts.

During the nine months ended September 30, 2021, we spent approximately $553.6 million on capital expenditures and on acquiring proved and unproved oil and gas properties.

This amount differs from the costs incurred amount of $589.7 million for the nine months ended September 30, 2021, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, and exploration overhead amounts.

The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, and the number and size of acquisitions.

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Our 2021 total capital program budget is between $650.0 million and $675.0 million.

We will continue to monitor the economic environment throughout the year and adjust our activity level as warranted.

We will continue to monitor the economic environment through the remainder of the year and adjust our activity level as warranted.

We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities, or a combination of both.

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We paid total consideration of $385.3 million, including net premiums, and paid $5.2 million of accrued interest related to the 2022 and 2024 Senior Notes.

During the first quarter of 2020, we repurchased a total of $40.7 million in aggregate principal amount of our 2022 Senior Notes in open market transactions at a discount, resulting in a net gain on extinguishment of debt of $12.2 million.

The 2021 Senior Secured Convertible Notes matured on July 1, 2021, and on that day, we used borrowings under our revolving credit facility to retire at par the outstanding principal amount of $65.5 million.

During the nine months ended September 30, 2020, we repurchased $103.2 million in aggregate principal amount of our 2022 Senior Notes and $29.0 million in aggregate principal amount of our 2024 Senior Notes in open market transactions at a discount, for a total settlement amount, excluding accrued interest, of $94.2 million, resulting in a net gain on extinguishment of debt of $25.1 million and $37.3 million for the three and nine months ended September 30, 2020, respectively.

During the second quarter of 2020, we completed the Exchange Offers, which resulted in the exchange of $718.9 million in aggregate principal amount of Old Notes for $446.7 million in aggregate principal amount of 2025 Senior Secured Notes.

Further, in connection with the Private Exchange, we tendered $53.5 million in cash to certain holders of the 2021 Senior Convertible Notes, which was borrowed against our revolving credit facility, and issued the Warrants.

Further, in connection with the Private Exchange, we tendered $53.5 million in cash to certain holders of the 2021 Senior Unsecured Convertible Notes, which was borrowed against our revolving credit facility, and issued the Warrants.

Please refer to Note 3 - Equity for additional discussion of the Warrants, including related impacts to equity and Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion of the debt transactions.

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Our Board of Directors periodically reviews this program as part of the allocation of our capital.

During the six months ended June 30, 2021, we did not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares of our common stock during the remainder of 2021.

Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2021, and 2020

The following tables present changes in cash flows between the six months ended June 30, 2021, and 2020, for our operating, investing, and financing activities.

The analysis following each table should be read in conjunction with our accompanying unaudited condensed consolidated statements of cash flows in Part I, Item 1 of this report.

During the nine months ended September 30, 2021, we did not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares of our common stock during the remainder of 2021.

Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2021, and 2020

The following tables present changes in cash flows between the nine months ended September 30, 2021, and 2020, for our operating, investing, and financing activities.

The analysis following each table should be read in conjunction with our accompanying statements of cash flows in Part I, Item 1 of this report.

Operating activities

For the Six Months Ended June 30, Amount Change Between Periods

For the Nine Months Ended

September 30, Amount Change Between Periods

(in millions)

Net cash provided by operating activities $ 730.1 $ 534.1 $ 196.0

Net cash provided by operating activities increased for the six months ended June 30, 2021, compared with the same period in 2020, primarily due to working capital changes resulting from the timing of cash receipts and disbursements.

During the six months ended June 30, 2021, compared with the same period in 2020, cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes increased $295.8 million, cash paid for LOE and ad valorem taxes decreased $22.7 million, and cash paid on settled derivative trades increased $379.9 million.

Net cash provided by operating activities increased for the nine months ended September 30, 2021, compared with the same period in 2020, primarily due to a $715.5 million increase in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, and a decrease in cash paid for G&A expense, LOE, and ad valorem taxes of $21.3 million, partially offset by an increase of $660.7 million in cash paid on settled derivative trades.

Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.

Investing activities

For the Six Months Ended June 30, Amount Change Between Periods

For the Nine Months Ended

September 30, Amount Change Between Periods

(in millions)

Net cash used in investing activities $ (544.8) $ (426.8) $ (118.0)

Net cash used in investing activities increased for the six months ended June 30, 2021, compared with the same period in 2020, due to increased capital expenditures of $60.0 million.

Net cash used in investing activities increased for the nine months ended September 30, 2021, compared with the same period in 2020, primarily due to increased capital expenditures of $130.5 million.

Financing activities

For the Six Months Ended June 30, Amount Change Between Periods

For the Nine Months Ended

September 30, Amount Change Between Periods

(in millions)

Net cash used in financing activities $ (155.6) $ (107.3) $ (48.3)

Net cash used in financing activities for the six months ended June 30, 2021, related to $385.3 million of net cash paid, including net premiums to fund the Tender Offer and the 2022 Senior Notes Redemption and net repayments under our revolving credit facility of $40.5 million, offset by net cash proceeds of $393.6 million from the issuance of our 2028 Senior Notes.

Net cash used in financing activities for the six months ended June 30, 2020, related to $81.8 million of net cash paid to repurchase certain of our Senior Notes, and $10.5 million of debt issuance costs incurred upon the issuance of the 2025 Senior Secured Notes, offset by net borrowings under our revolving credit facility of $70.5 million.

Net cash used in financing activities for the nine months ended September 30, 2021, related to $385.3 million of net cash paid, including net premiums to fund the Tender Offer and the 2022 Senior Notes Redemption, offset by net cash proceeds of $392.8 million from the issuance of our 2028 Senior Notes.

Additionally, we paid $65.5 million to retire our 2021 Senior Secured Convertible Notes and had net repayments under our revolving credit facility of $93.0 million.

Net cash used in financing activities for the nine months ended September 30, 2020, related to $147.8 million of net cash paid to repurchase certain of our Senior Notes, and $12.9 million of debt issuance costs incurred upon the issuance of the 2025 Senior Secured Notes, partially offset by net borrowings under our revolving credit facility of $55.5 million.

Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

1 unchanged sentence

We are exposed to market risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility.

As of June 30, 2021, we had a $52.5 million balance on our revolving credit facility.

As of September 30, 2021, we had a zero balance on our revolving credit facility.

Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months.

To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not impact results of operations or cash flows.

To the extent that the

interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not impact results of operations or cash flows.

Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows.

Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Unsecured Notes or fixed-rate Senior Secured Notes but can impact their fair values.

As of June 30, 2021, our outstanding principal amount of fixed-rate debt totaled $2.2 billion and our floating-rate debt outstanding totaled $52.5 million.

As of September 30, 2021, our outstanding principal amount of fixed-rate debt totaled $2.1 billion and we had no floating-rate debt outstanding.

Please refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Notes.

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The markets for oil, gas, and NGLs have been volatile, especially over the last several years.

Commodity prices have improved from historic lows in 2020 resulting from the impacts of the Pandemic, however, future infection rate surges or outbreaks could have further negative impacts on prices.

Commodity prices have improved from historic lows in 2020 resulting from the impacts of the Pandemic, however, future case surges, outbreaks, COVID-19 virus variants, the potential that current vaccines may be less effective or ineffective against future COVID-19 virus variants, and the risk that large groups of the population may not receive vaccinations against COVID-19, could have further negative impacts on prices.

The realized prices we receive for our production also depend on numerous factors that are typically beyond our control.

Based on our production for the six months ended June 30, 2021, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced our oil, gas, and NGL production revenues by approximately $74.2 million, $17.8 million, and $6.6 million, respectively.

If commodity prices had been 10 percent lower, our net derivative settlements for the six months ended June 30, 2021, would have offset the declines in oil, gas, and NGL production revenue by approximately $82.1 million.

Based on our production for the nine months ended September 30, 2021, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced our oil, gas, and NGL production revenues by approximately $130.1 million, $32.7 million, and $11.8 million, respectively.

If commodity prices had been 10 percent lower, our net derivative settlements for the nine months ended September 30, 2021, would have offset the declines in oil, gas, and NGL production revenue by approximately $133.6 million.

We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices.

The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices.

As of June 30, 2021, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative

instruments would have changed our net derivative positions for these products by approximately $145.1 million, $28.3 million, and $11.8 million, respectively.

As of September 30, 2021, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products by approximately $119.9 million, $31.7 million, and $12.0 million, respectively.

Off-Balance Sheet Arrangements

2 unchanged sentences

If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements.

We have not been involved in any unconsolidated SPE transactions during the six months ended June 30, 2021, or through the filing of this report.

We have not been involved in any unconsolidated SPE transactions during the nine months ended September 30, 2021, or through the filing of this report.

Critical Accounting Policies and Estimates

13 unchanged sentences

In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes would be entitled to exercise all of their remedies for default.

The following table provides reconciliations of our net loss (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:

For the Three Months Ended June 30, For the Six Months Ended June 30,

The following table provides reconciliations of our net income (loss) (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:

For the Three Months Ended

September 30, For the Nine Months Ended

September 30,

2021 2020 2021 2020

(in thousands)

Net loss (GAAP) $ (222,995) $ (89,252) $ (474,264) $ (501,147)

Net income (loss) (GAAP) $ 85,593 $ (98,292) $ (388,671) $ (599,439)

Interest expense 40,861 41,519 120,268 123,385

23 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis