Exhibit 99.1

Northern Oil and Gas, Inc. Announces Second Quarter 2021 Results and Updates Guidance

HIGHLIGHTS

Second quarter total production of 54,623 Boe per day, up 42% sequentially from the first quarter of 2021
Oil production of 33,346 Bbl per day, up 14% sequentially from the first quarter of 2021
Second quarter GAAP cash flow from operations of $106.2 million. Excluding changes in net working capital, cash flow from operations was $118.4 million, up 42% from the first quarter of 2021
Total capital expenditures of $68.4 million during the second quarter, excluding the closing of the Marcellus acquisition on April 1, 2021
Free Cash Flow (non-GAAP) of $46.2 million, post-preferred stock dividends. See “Non-GAAP Financial Measures” below
Completed a 5.75 million share common stock offering to fund the acquisition of over $100 million in core Permian Basin acquisitions that signed during the second quarter, the last and largest of which closed on August 2, 2021
The Board of Directors has declared Northern’s second quarterly common stock dividend of $0.045 per share, a 50% increase from the prior quarter, payable October 29, 2021 to stockholders of record on September 30, 2021
Updated 2021 guidance includes increased annual production and reduced capital expenditures


MINNEAPOLIS (BUSINESS WIRE) - August 5, 2021 - Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”) today announced the company’s second quarter results.

MANAGEMENT COMMENTS

“This was one of the strongest operational and financial quarters on record for the Company,” commented Nick O’Grady, Northern’s Chief Executive Officer. “Year-to-date Northern has executed on several large bolt-on acquisitions and significantly improved its balance sheet. With the active management of our portfolio, we have driven substantial production and cash flow growth. Our focus on return on capital and high-quality operators and acreage is showing up directly on the bottom line. Our long term plan remains unchanged: building a diversified, low-leverage entity with the ability to deliver substantial cash returns. The opportunity set for value creation in front of us is stronger than ever.”

SECOND QUARTER FINANCIAL RESULTS

Oil and natural gas sales for the second quarter were $225.7 million, up 43% over the first quarter. Second quarter GAAP net loss, inclusive of a $173.1 million non-cash net mark-to-market loss on derivatives, was $90.6 million or $1.49 per diluted share. Second quarter Adjusted Net Income was $65.0 million or $0.92 per diluted share, up from $10.7 million or $0.21 per diluted share in the prior year. Adjusted EBITDA in the second quarter was $132.8 million, up 35% from the first quarter of 2021. See “Non-GAAP Financial Measures” below.

PRODUCTION

Second quarter production was 54,623 Boe per day, a 42% increase from the first quarter of 2021. Oil represented 61% of total production in the second quarter. Oil production was 33,346 Bbl per day, a 14% increase over the first quarter. Northern has continued to see stellar well performance above target and accelerated development, with wells turning in-line ahead of schedule due to strong strip prices. Northern had 10.5 net wells turned in-line during the second quarter, compared to 6.7 net wells turned in-line in the first quarter of 2021. Northern’s Marcellus properties produced 63.0 MMcf per day in the second quarter, consistent with expectations. The first EQT-operated wells came online in early July 2021.

PRICING

During the second quarter, NYMEX West Texas Intermediate (“WTI”) crude oil averaged $66.19 per Bbl, and NYMEX natural gas at Henry Hub averaged $2.92 per million cubic feet (“Mcf”). Northern’s unhedged net realized oil price in the second quarter was $60.73, representing a $5.46 differential to WTI prices. Northern’s unhedged net realized gas price in the second quarter was $3.57 per Mcf, representing approximately 122% realizations compared with Henry Hub pricing.





OPERATING COSTS

Lease operating costs were $42.7 million in the second quarter of 2021, or $8.59 per Boe, down 13% on a per unit basis compared to the first quarter of 2021. Reductions in costs were driven by the closing of the Marcellus acquisition, partially offset by workover costs and higher processing costs associated with the ramp in overall production. Second quarter general and administrative (“G&A”) costs totaled $7.6 million or $1.53 per Boe. This includes $3.0 million of legal and other transaction expenses in connection with the Marcellus acquisition and $0.8 million of non-cash stock-based compensation. Northern’s G&A costs excluding these amounts totaled $3.8 million or $0.77 per Boe in the second quarter, record low unit costs for the Company.

CAPITAL EXPENDITURES AND ACQUISITIONS

Capital spending for the second quarter was $68.4 million, made up of $41.9 million of organic drilling and completion (“D&C”) capital and $26.5 million of total acquisition spending and other items, inclusive of ground game D&C spending. Northern added 10.5 net wells to production in the second quarter. Wells in process increased to 43.8 net wells at the end of the second quarter, compared to 22.7 at the end of the first quarter, driven by the acquisition of the Marcellus properties. On the ground game acquisition front, Northern closed on 11 transactions during the second quarter totaling 2.8 net wells, 624 net mineral acres, and 107 net royalty acres (standardized to a 1/8 royalty interest).

PERMIAN BASIN ACQUISITIONS

On June 16, 2021, Northern announced that it entered into three definitive agreements to acquire non-operated interests across approximately 2,900 net acres located in the heart of Lea and Eddy Counties, New Mexico and Reeves County, Texas. The assets include 5.3 net producing wells, 5.0 net wells in process and an additional 23.1 net undrilled locations ascribed to the core zones including the Wolfcamp A, Wolfcamp B and 1st through 3rd Bone Springs. The assets are operated primarily by Mewbourne Oil Company, Colgate Energy, ConocoPhillips and EOG Resources. The acquisitions were all closed by August 2, 2021. Northern has updated corporate guidance for the acquired assets in the guidance section below.

LIQUIDITY AND CAPITAL RESOURCES

Northern had total liquidity of $411.2 million as of June 30, 2021, consisting of cash of $4.8 million, the Permian acquisition deposit of $9.4 million, and $397.0 million of committed borrowing availability under the revolving credit facility.

In June 2021, Northern additionally strengthened its balance sheet through a common equity transaction alongside of its announcement of a series of Permian Basin acquisitions. Northern issued 5.75 million shares of common equity for gross proceeds of $100.2 million. On May 17, 2021, Northern redeemed and retired the remaining $15.7 million of its 2023 Senior Notes.

On August 2, 2021, Northern funded the purchase price, including typical closing adjustments, of $105.6 million for the largest of its recently announced Permian acquisitions, funded in part by the $9.4 million deposit made during the second quarter, and borrowings under its credit facility.

STOCKHOLDER RETURNS

In April 2021, Northern’s Board of Directors declared all current and accrued cash dividends for Northern’s Series A Preferred Stock, paid on May 15, 2021 in the total amount of $22.0 million.

In May 2021, Northern’s Board of Directors declared its first ever regular quarterly cash dividend for Northern’s common stock of $0.03 per share for stockholders of record as of June 30, 2021, payable July 30, 2021.
On August 3, 2021, Northern’s Board of Directors declared a regular quarterly cash dividend for Northern’s common stock of $0.045 per share for stockholders of record as of September 30, 2021, payable October 29, 2021. This represents a 50% increase from the prior quarter.



2021 FULL YEAR GUIDANCE
(all forecasts are provided on a 2-stream production basis)

PriorCurrent
Annual Production (Boe per day)
47,167 - 53,424 (1)
49,500 - 54,250
Oil as a Percentage of Sales Volumes
62% - 64% (1)
63% - 64%
Net Wells Added to Production
35.5 - 37.8 (1)
38 - 40
Total Capital Expenditures (in millions) (2)
$215 - $270$215 - $260
---------------------------
(1)    Prior guidance did not include Permian acquisitions which closed on August 2, 2021, and is calculated based on April 1, 2021 closing of the Marcellus acquisition.
(2)    Excludes non-budgeted acquisitions of Marcellus and Permian properties, but includes post-closing capital expenditures.

Operating Expenses and Differentials:PriorCurrent
Production Expenses (per Boe)
 - (3)
$8.60 - $8.90
Production Taxes10% of Net Oil Revenues, $0.06 per Mcf for Natural Gas9% - 10% of Oil & Gas Sales
Average Differential to NYMEX WTI (per Bbl)
$6.50 - $8.50$6.25 - $7.25
Average Realization as a Percentage of NYMEX Henry Hub (per Mcf)
 - (3)
80% - 100%
---------------------------
(3)    Northern did not previously provide full corporate operating cost and gas realization guidance including the Marcellus, Permian and Williston Properties.

PriorCurrent
General and Administrative Expense (per Boe):
Cash (excluding Marcellus and Permian transaction costs)
$0.80 - $0.90$0.80 - $0.85
Non-Cash$0.20$0.18





SECOND QUARTER 2021 RESULTS

The following tables set forth selected operating and financial data for the periods indicated.

 Three Months Ended June 30,
 20212020% Change
Net Production:
Oil (Bbl)3,034,442 1,659,293 83 %
Natural Gas and NGLs (Mcf)11,617,308 3,041,418 282 %
Total (Boe)4,970,660 2,166,196 129 %
Average Daily Production:
Oil (Bbl)33,346 18,234 83 %
Natural Gas and NGLs (Mcf)127,663 33,422 282 %
Total (Boe)54,623 23,804 129 %
Average Sales Prices:
Oil (per Bbl)$60.73 $17.35 250 %
Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)(8.16)46.19 
Oil Net of Settled Oil Derivatives (per Bbl)52.57 63.54 (17)%
Natural Gas and NGLs (per Mcf)3.57 (2.67)
Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf)(0.27)0.26 
Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf)3.30 (2.41)
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives45.41 9.54 376 %
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe)(5.60)35.75 
Realized Price on a Boe Basis Including Settled Commodity Derivatives39.81 45.29 (12)%
Costs and Expenses (per Boe):
Production Expenses$8.59 $12.30 (30)%
Production Taxes3.72 0.89 318 %
General and Administrative Expenses1.53 2.17 (29)%
Depletion, Depreciation, Amortization and Accretion6.22 16.97 (63)%
Net Producing Wells at Period End588.6 466.0 26 %





HEDGING

Northern hedges portions of its expected production volumes to increase the predictability of its cash flow and to help maintain a strong financial position. The following table summarizes Northern’s open crude oil commodity derivative swap contracts scheduled to settle after June 30, 2021.

Crude Oil Commodity Derivative Swaps(1)
Contract PeriodVolume (Bbls)Volume (Bbls/Day)Weighted Average Price (per Bbl)
2021:
Q32,197,26023,883$54.63
Q42,200,70623,921$54.26
2022:
Q11,968,73021,875$55.80
Q21,865,50020,500$56.42
Q31,886,00020,500$55.89
Q41,748,00019,000$55.48
2023:
Q1472,5005,250$57.92
Q2295,7503,250$60.54
_____________
(1)This table does not include volumes subject to swaptions and call options, which could increase the amount of volumes hedged at the option of Northern’s counterparties. This table also does not include basis swaps. For additional information, see Note 11 to our financial statements included in our Form 10-Q filed with the SEC for the quarter ended June 30, 2021.

The following table summarizes Northern’s open natural gas commodity derivative swap contracts scheduled to settle after June 30, 2021.

Natural Gas Commodity Derivative Swaps
Contract PeriodGas (MMBTU)Volume (MMBTU/Day)Weighted Average Price (per Mcf)
2021:
Q38,979,02897,598$2.82
Q48,784,21095,481$2.82
2022:
Q16,257,29169,525$3.07
Q25,460,00060,000$2.95
Q35,520,00060,000$2.95
Q44,300,00046,739$2.94

The following table presents Northern’s settlements on commodity derivative instruments and unsettled gains and losses on open commodity derivative instruments for the periods presented, which is included in the revenue section of Northern’s statement of operations:

 Three Months Ended
June 30,
Six Months Ended
June 30,
(In thousands)2021202020212020
Cash Received (Paid) on Derivatives:$(27,855)$77,439 $(35,152)$108,944 
Non-Cash Gain (Loss) on Derivatives:(173,057)(150,077)(301,695)194,999 
Gain (Loss) on Derivative Instruments, Net$(200,912)$(72,638)$(336,847)$303,943 




CAPITAL EXPENDITURES & DRILLING ACTIVITY
(In millions, except for net well data)Three Months Ended June 30, 2021
Capital Expenditures Incurred:
Organic Drilling and Development Capital Expenditures$41.9 
Ground Game Drilling and Development Capital Expenditures$7.0 
Ground Game Acquisition Capital Expenditures$17.7 
Other$1.9 
Marcellus Acquisition$149.7 
Net Wells Added to Production10.5 
Net Producing Wells (Period-End)588.6 
Net Wells in Process (Period-End)43.8 
Increase in Wells in Process over Prior Period21.0 
Weighted Average Gross AFE for Wells Elected to$6.4 million

SECOND QUARTER 2021 EARNINGS RELEASE CONFERENCE CALL

In conjunction with Northern’s release of its financial and operating results, investors, analysts and other interested parties are invited to listen to a conference call with management on Thursday, August 5, 2021 at 10:00 a.m. Central Time.

Those wishing to listen to the conference call may do so via webcast or phone as follows:

Webcast: https://78449.themediaframe.com/dataconf/productusers/nog/mediaframe/46117/indexl.html
Dial-In Number: (866) 373-3407 (US/Canada) and (412) 902-1037 (International)
Conference ID: 13721948 - Northern Oil and Gas, Inc. Second Quarter 2021 Earnings Call
Replay Dial-In Number: (877) 660-6853 (US/Canada) and (201) 612-7415 (International)
Replay Access Code: 13721948 - Replay will be available through August 12, 2021

UPCOMING CONFERENCE SCHEDULE

Enercom
Denver, CO
August 16-17, 2021

Bank of America E&P Bus Tour
August 24, 2021

ABOUT NORTHERN OIL AND GAS

Northern Oil and Gas, Inc. is a company with a primary strategy of investing in non-operated minority working and mineral interests in oil & gas properties, with a core area of focus in the premier basins within the United States. More information about Northern Oil and Gas, Inc. can be found at www.northernoil.com.

SAFE HARBOR

This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this release regarding Northern’s financial position, operating and financial performance, business strategy, plans and objectives of management for future operations, industry



conditions, and indebtedness covenant compliance are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future production and sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond Northern’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in crude oil and natural gas prices; the pace of drilling and completions activity on Northern’s properties and properties pending acquisition; Northern’s ability to acquire additional development opportunities; potential or pending acquisition transactions; Northern’s ability to consummate pending acquisitions, and the anticipated timing of such consummation; the projected capital efficiency savings and other operating efficiencies and synergies resulting from Northern’s acquisition transactions; integration and benefits of property acquisitions, or the effects of such acquisitions on Northern’s cash position and levels of indebtedness; changes in Northern’s reserves estimates or the value thereof; disruptions to Northern’s business due to acquisitions and other significant transactions; infrastructure constraints and related factors affecting Northern’s properties; ongoing legal disputes over and potential shutdown of the Dakota Access Pipeline; the COVID-19 pandemic and its related economic repercussions and effect on the oil and natural gas industry; general economic or industry conditions, nationally and/or in the communities in which Northern conducts business; changes in the interest rate environment, legislation or regulatory requirements; conditions of the securities markets; Northern’s ability to raise or access capital; changes in accounting principles, policies or guidelines; and financial or political instability, health-related epidemics, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting Northern’s operations, products and prices.

Northern has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond Northern’s control. Northern does not undertake any duty to update or revise any forward-looking statements, except as may be required by the federal securities laws.


CONTACT:

Mike Kelly, CFA
Chief Strategy Officer
952-476-9800
mkelly@northernoil.com





CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)

Three Months Ended
June 30,
Six Months Ended
June 30,
(In thousands, except share and per share data)2021202020212020
Revenues
Oil and Gas Sales$225,717 $20,664 $383,048 $150,860 
Gain (Loss) on Commodity Derivatives, Net(200,912)(72,638)(336,847)303,943 
Other Revenue— 12 
Total Revenues24,805 (51,971)46,202 454,815 
Operating Expenses
Production Expenses42,699 26,638 77,010 63,974 
Production Taxes18,514 1,917 31,967 13,813 
General and Administrative Expense7,604 4,710 14,388 9,580 
Depletion, Depreciation, Amortization and Accretion30,908 36,756 62,128 98,565 
Impairment Expense— 762,716 — 762,716 
Total Operating Expenses99,725 832,737 185,493 948,648 
Loss From Operations(74,920)(884,708)(139,291)(493,833)
Other Income (Expense)
Interest Expense, Net of Capitalization(15,024)(13,957)(28,534)(30,508)
Gain (Loss) on Unsettled Interest Rate Derivatives, Net121 (752)362 (1,429)
Gain (Loss) on Extinguishment of Debt, Net(494)217 (13,087)(5,310)
Contingent Consideration Loss(250)— (375)— 
Other Income (Expense)— — 
Total Other Income (Expense)(15,643)(14,492)(41,629)(37,247)
Loss Before Income Taxes(90,563)(899,200)(180,920)(531,080)
Income Tax Provision (Benefit)— — — (166)
Net Loss$(90,563)$(899,200)$(180,920)$(530,914)
Cumulative Preferred Stock Dividend(3,719)(3,788)(7,550)(7,517)
Net Loss Attributable to Common Stockholders$(94,282)$(902,988)$(188,470)$(538,431)
Net Loss Per Common Share – Basic*$(1.55)$(21.74)$(3.27)$(13.15)
Net Loss Per Common Share – Diluted*$(1.55)$(21.74)$(3.27)$(13.15)
Weighted Average Common Shares Outstanding – Basic*60,694,795 41,535,601 57,633,454 40,950,927 
Weighted Average Common Shares Outstanding – Diluted*60,694,795 41,535,601 57,633,454 40,950,927 
___________
*Adjusted for the 1-for-10 reverse stock split.




CONDENSED BALANCE SHEETS

(In thousands, except par value and share data)June 30, 2021December 31, 2020
Assets(Unaudited)
Current Assets:  
Cash and Cash Equivalents$4,843 $1,428 
Accounts Receivable, Net131,165 71,015 
Advances to Operators433 476 
Prepaid Expenses and Other2,705 1,420 
Derivative Instruments518 51,290 
Total Current Assets139,664 125,629 
Property and Equipment:  
Oil and Natural Gas Properties, Full Cost Method of Accounting  
Proved4,638,415 4,393,533 
Unproved21,347 10,031 
Other Property and Equipment2,501 2,451 
Total Property and Equipment4,662,263 4,406,015 
Less – Accumulated Depreciation, Depletion and Impairment(3,732,183)(3,670,811)
Total Property and Equipment, Net930,080 735,204 
Derivative Instruments32 111 
Acquisition Deposit9,400 — 
Other Noncurrent Assets, Net12,634 11,145 
Total Assets$1,091,810 $872,089 
Liabilities and Stockholders' Equity (Deficit)
Current Liabilities:  
Accounts Payable$49,186 $35,803 
Accrued Liabilities91,724 68,673 
Accrued Interest16,877 8,341 
Derivative Instruments140,694 3,078 
Contingent Consideration513 493 
Current Portion of Long-term Debt— 65,000 
Other Current Liabilities1,843 1,087 
Total Current Liabilities300,837 182,475 
Long-term Debt801,998 879,843 
Derivative Instruments127,526 14,659 
Asset Retirement Obligations26,176 18,366 
Other Noncurrent Liabilities3,490 50 
Total Liabilities$1,260,027 $1,095,393 
Commitments and Contingencies (Note 8)
Stockholders’ Equity (Deficit)  
Preferred Stock, Par Value $.001; 5,000,000 Shares Authorized;
2,218,732 Series A Shares Outstanding at 6/30/2021
2,218,732 Series A Shares Outstanding at 12/31/2020



Common Stock, Par Value $.001; 135,000,000* Shares Authorized;
 66,164,399* Shares Outstanding at 6/30/2021
 45,908,779* Shares Outstanding at 12/31/2020
468 448 
Additional Paid-In Capital1,792,589 1,556,602 
Retained Deficit(1,961,276)(1,780,356)
Total Stockholders’ Equity (Deficit)(168,217)(223,304)
Total Liabilities and Stockholders’ Equity (Deficit) $1,091,810 $872,089 
__________
*Adjusted for the 1-for-10 reverse stock split.



Non-GAAP Financial Measures

Adjusted Net Income, Adjusted EBITDA and Free Cash Flow are non-GAAP measures. Northern defines Adjusted Net Income (Loss) as net income (loss) excluding (i) (gain) loss on unsettled commodity derivatives, net of tax, (ii) loss on extinguishment of debt, net of tax, (iii) contingent consideration loss, net of tax, (iv) acquisition transaction costs, net of tax, and (v) gain on unsettled interest rate derivatives, net of tax. Northern defines Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization and accretion, (iv) non-cash stock-based compensation expense, (v) loss on extinguishment of debt, (vi) contingent consideration loss, (vii) acquisition transaction costs, (viii) (gain) loss on unsettled commodity derivatives, (ix) gain (loss) on unsettled interest rate derivatives, and (x) impairment expense. Northern defines Free Cash Flow as cash flows from operations before changes in working capital and other items, less (i) capital expenditures, excluding non-budgeted acquisitions and (ii) preferred stock dividends. A reconciliation of each of these measures to the most directly comparable GAAP measure is included below.

Management believes the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of current financial performance. Management believes Adjusted Net Income and Adjusted EBITDA provide useful information to both management and investors by excluding certain expenses and unrealized commodity gains and losses that management believes are not indicative of Northern’s core operating results. Management believes that Free Cash Flow is useful to investors as a measure of a company’s ability to internally fund its budgeted capital expenditures, to service or incur additional debt, and to measure success in creating stockholder value. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring Northern’s performance, and management believes it is providing investors with financial measures that most closely align to its internal measurement processes. The non-GAAP financial measures included herein may be defined differently than similar measures used by other companies and should not be considered an alternative to, or more meaningful than, the comparable GAAP measures. From time to time Northern provides forward-looking Free Cash Flow estimates or targets; however, Northern is unable to provide a quantitative reconciliation of the forward looking non-GAAP measure to its most directly comparable forward looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward looking GAAP measure. The reconciling items in future periods could be significant.




Reconciliation of Adjusted Net Income

 Three Months Ended
June 30,
Six Months Ended
June 30,
(In thousands, except share and per share data)2021202020212020
Net Loss$(90,563)$(899,200)$(180,920)$(530,914)
Add:    
Impact of Selected Items:    
(Gain) Loss on Unsettled Commodity Derivatives173,057 150,077 301,695 (194,999)
(Gain) Loss on Extinguishment of Debt494 (217)13,087 5,310 
Contingent Consideration Loss250 — 375 — 
Acquisition Transaction Costs3,016 — 5,527 — 
(Gain) Loss on Unsettled Interest Rate Derivatives(121)752 (362)1,429 
Selected Items, Before Income Taxes176,695 913,328 320,323 574,456 
Income Tax of Selected Items(1)
(21,102)(3,461)(34,154)(10,668)
Selected Items, Net of Income Taxes155,593 909,866 286,169 563,788 
Adjusted Net Income$65,030 $10,667 $105,249 $32,874 
Weighted Average Shares Outstanding – Basic60,694,795 41,535,601 57,633,454 40,950,927 
Weighted Average Shares Outstanding – Diluted70,526,168 51,556,972 67,457,298 50,989,784 
Net Income (Loss) Per Common Share – Basic$(1.49)$(21.65)$(3.14)$(12.96)
Add:    
Impact of Selected Items, Net of Income Taxes2.56 21.91 4.97 13.76 
Adjusted Net Income Per Common Share – Basic$1.07 $0.26 $1.83 $0.80 
Net Income (Loss) Per Common Share – Diluted$(1.28)$(17.44)$(2.68)$(10.41)
Add:    
Impact of Selected Items, Net of Income Taxes2.20 17.65 4.24 11.05 
Adjusted Net Income Per Common Share – Diluted$0.92 $0.21 $1.56 $0.64 
______________
(1)For the three and six months ended June 30, 2021, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $22.2 million and $44.3 million, respectively, for a change in valuation allowance. For the three and six months ended June 30, 2020, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $220.3 million and $130.1 million, respectively, for a change in valuation allowance.





Reconciliation of Adjusted EBITDA

Three Months Ended
June 30,
Six Months Ended
June 30,
(In thousands)2021202020212020
Net Loss$(90,563)$(899,200)$(180,920)$(530,914)
Add:    
Interest Expense15,024 13,957 28,534 30,508 
Income Tax Provision (Benefit)— — — (166)
Depreciation, Depletion, Amortization and Accretion30,908 36,756 62,128 98,565 
Non-Cash Stock-Based Compensation779 1,214 — 2,293 
(Gain) Loss on Extinguishment of Debt494 (217)13,087 5,310 
Contingent Consideration Loss250 — 375 — 
Acquisition Transaction Costs3,016 — 5,527 — 
(Gain) Loss on Unsettled Interest Rate Derivatives(121)752 (362)1,429 
(Gain) Loss on Unsettled Commodity Derivatives173,057 150,077 301,695 (194,999)
Impairment Expense— 762,716 — 762,716 
Adjusted EBITDA$132,844 $66,055 $231,614 $174,742 


Reconciliation of Free Cash Flow

Three Months Ended
June 30,
(In thousands)2021
Net Cash Provided by Operating Activities$106,186 
Exclude: Changes in Working Capital and Other Items12,204 
Less: Capital Expenditures (1)
(68,445)
Less: Series A Preferred Dividends(3,719)
Free Cash Flow$46,226 
_______________

(1) Capital expenditures are calculated as follows:

Three Months Ended
June 30,
(In thousands)2021
Cash Paid for Capital Expenditures$169,679 
Less: Non-Budgeted Acquisitions(119,207)
Plus: Change in Accrued Capital Expenditures and Other17,973 
Capital Expenditures$68,445