Northern Oil and Gas, Inc.
Aug 8, 2017

Northern Oil and Gas, Inc. Announces 2017 Second Quarter Results

MINNEAPOLIS, Aug. 8, 2017 /PRNewswire/ -- Northern Oil and Gas, Inc. (NYSE American: NOG) today announced 2017 second quarter results. 

HIGHLIGHTS

  • Daily production increased 4% sequentially to average 13,794 barrels of oil equivalent ("Boe") per day in the second quarter, for a total of 1,255,280 Boe.
  • Northern added 4.3 net wells to production during the second quarter of 2017.
  • The 6.2 net wells that Northern elected to participate in during the first half of 2017 have an estimated internal rate of return of approximately 30% at a $50/Bbl flat pricing assumption.
  • At June 30, 2017, Northern maintained a strong list of wells in process totaling 16.1 net wells that have an estimated internal rate of return of approximately 30% at a $50/Bbl flat pricing assumption.

Northern's GAAP net income for the second quarter of 2017 was $13.8 million.  Adjusted net income for the quarter was a loss of $0.2 million.  Adjusted EBITDA for the quarter was $30.7 million.  See "Non-GAAP Financial Measures" below for additional information on these measures.

MANAGEMENT COMMENT

"Strong second quarter net well additions drove our production levels above internal expectations for the quarter," commented Northern's Interim CEO and CFO, Tom Stoelk.  "Our growing list of high quality wells awaiting completion and the further productivity improvements we are seeing in 2017 gives us confidence that we'll meet or exceed our original production goals for the year.  Our goal is to position ourselves to capitalize on the significant growth and consolidation opportunities we expect to see going forward.  Our continued focus on capital allocation, growing reserves and production is helping prepare us for future opportunities and value creation as the industry environment improves."

GUIDANCE

Northern's prior guidance on annual production remains unchanged.  Management's current expectations for the second half of 2017 operating metrics are as follows:

 



Second Half 2017

Operating Expenses:



Production Expenses (per Boe)


$9.25 - $9.50

Production Taxes (% of Oil & Gas Sales)


9.5%

General and Administrative Expense (per Boe)


$3.25 - $3.50




Average Differential to NYMEX WTI


 $6.50 - $8.50

 

LIQUIDITY

At June 30, 2017, Northern had $155.0 million in outstanding borrowings under its revolving credit facility.  In May 2017, Northern completed the semi-annual redetermination under its revolving credit facility with the borrowing base established at $325.0 million.  Based on this new borrowing base, Northern had available liquidity of $173.8 million as of June 30, 2017, composed of $3.8 million in cash and $170.0 million of revolving credit facility availability.

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 derivative contracts scheduled to settle after June 30, 2017.

 



Swaps


Collars

Contract Period


Volume (Bbls)


Weighted Average Price (per Bbl)


Volume (Bbls)


Weighted Average Floor - Ceiling Prices (per Bbl)

2017:









3Q


632,000


$53.36


75,000


$50.00 - $60.06

4Q


632,000


$53.36


75,000


$50.00 - $60.06

2018:









1Q


510,000


$53.24


90,000


$50.00 - $60.25

2Q


511,000


$53.24


90,000


$50.00 - $60.25

3Q


492,000


$53.38


90,000


$50.00 - $60.25

4Q


364,000


$52.94


90,000


$50.00 - $60.25

 

CAPITAL EXPENDITURES & DRILLING ACTIVITY



Three Months Ended June 30, 2017

Capital Expenditures Incurred:



Drilling, Completion & Capitalized Workover Expense


$27.9 million

Acreage


$1.8 million

Other


$1.0 million




Net Wells Added to Production


4.3

Net Producing Wells (Period-End)


218.8




Net Wells in Process (Period-End)


16.1




Weighted Average AFE for In-Process Wells (Period-End)


$7.4 million

 

The weighted average authorization for expenditure (or AFE) cost for wells that Northern elected to participate in (consented) was $7.8 million for the second quarter of 2017, and $7.1 million for the first half of 2017.

ACREAGE

As of June 30, 2017, Northern has leased approximately 148,571 net acres targeting the Williston Basin Bakken and Three Forks formations.  As of June 30, 2017, approximately 86% of Northern's North Dakota acreage position, and approximately 84% of Northern's total acreage position was developed, held by production or held by operations.

SECOND QUARTER 2017 RESULTS

The following table sets forth selected operating and financial data for the periods indicated.

 


Three Months Ended June 30,


2017


2016


% Change

Net Production:






Oil (Bbl)

1,054,263



1,087,710



(3)

%

Natural Gas and NGLs (Mcf)

1,206,103



1,080,897



12

%

Total (Boe)

1,255,280



1,267,860



(1)

%







Average Daily Production:






Oil (Bbl)

11,585



11,953



(3)

%

Natural Gas and NGLs (Mcf)

13,254



11,878



12

%

Total (Boe)

13,794



13,933



(1)

%







Net Sales:






Oil Sales

$

43,531,170



$

40,851,527



7

%

Natural Gas and NGL Sales

4,849,836



1,676,320



189

%

Gain (Loss) on Derivative Instruments, Net

16,513,032



(10,522,948)



(257)

%

Other Revenue

7,844



9,327



(16)

%

Total Revenues

64,901,882



32,014,226



103

%







Average Sales Prices:






Oil (per Bbl)

$

41.29



$

37.56



10

%

Effect of (Loss) Gain on Settled Derivatives on Average Price (per Bbl)

2.22



18.37



(88)

%

Oil Net of Settled Derivatives (per Bbl)

43.51



55.93



(22)

%

Natural Gas and NGLs (per Mcf)

4.02



1.55



159

%

Realized Price on a Boe Basis Including all Realized Derivative Settlements

40.41



49.30



(18)

%







Operating Expenses:






Production Expenses

$

12,137,540



$

11,081,973



10

%

Production Taxes

4,439,774



4,220,712



5

%

General and Administrative Expense

4,317,139



4,586,275



(6)

%

Depletion, Depreciation, Amortization and Accretion

13,682,452



16,176,863



(15)

%







Costs and Expenses (per Boe):






Production Expenses

$

9.67



$

8.74



11

%

Production Taxes

3.54



3.33



6

%

General and Administrative Expense

3.44



3.62



(5)

%

Depletion, Depreciation, Amortization and Accretion

10.90



12.76



(15)

%

Net Producing Wells at Period End

218.8



208.1



5

%

 

Oil and Natural Gas Sales

In the second quarter of 2017, oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 14% as compared to the second quarter of 2016, driven by a 15% increase in realized prices, excluding the effect of settled derivatives, which was partially offset by a 1% decrease in production.  The higher average realized price in the second quarter of 2017 as compared to the same period in 2016 was principally driven by higher average NYMEX oil and natural gas prices and a lower oil price differential.  Oil price differential during the second quarter of 2017 was $6.86 per barrel, as compared to $8.08 per barrel in the second quarter of 2016.

Derivative Instruments (Hedges)

Northern enters into derivative instruments to manage the price risk attributable to future oil production. Gain (loss) on derivative instruments, net was a gain of $16.5 million in the second quarter of 2017, compared to a loss of $10.5 million in the second quarter of 2016.  Gain (loss) on derivative instruments, net is comprised of (i) cash gains and losses recognized on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses incurred on derivative instruments outstanding at period end.

 


Three Months Ended

June 30,


2017


2016

Cash Received (Paid) on Derivatives

$

2,341,030



$

19,983,750


Non-Cash Gain (Loss) on Derivatives

14,172,002



(30,506,698)


Gain (Loss) on Derivative Instruments, Net

$

16,513,032



$

(10,522,948)


 

The average NYMEX oil price for the second quarter of 2017 was $48.15 compared to $45.64 for the second quarter of 2016.  Northern's average realized price (including all cash derivative settlements) in the second quarter of 2017 was $40.41 per Boe compared to $49.30 per Boe in the second quarter of 2016.  The gain (loss) on settled derivatives increased the average realized price per Boe by $1.86 in the second quarter of 2017 and increased the average realized price per Boe by $15.76 in the second quarter of 2016.

Production Expenses

Production expenses were $12.1 million in the second quarter of 2017 compared to $11.1 million in the second quarter of 2016.  On a per unit basis, production expenses increased to $9.67 per Boe in the second quarter of 2017, compared to $8.74 per Boe in the second quarter of 2016.  On an absolute dollar basis, the increase in production expenses in the second quarter of 2017 as compared to the second quarter of 2016 was primarily due to a $0.2 million increase in processing costs and a $0.5 million increase in workover and maintenance costs, as well as a 5% increase in the total number of net producing wells.  In an effort to increase production, workover expenses have increased in 2017 compared to 2016 as new operators have assumed the operations of properties previously managed by financially stressed companies.

Production Taxes

Production taxes were $4.4 million in the second quarter of 2017 compared to $4.2 million in the second quarter of 2016.  The increase is due to higher commodity prices, which increased oil and natural gas sales in the second quarter of 2017 as compared to the second quarter of 2016.  As a percentage of oil and natural gas sales, production taxes were 9.2% and 9.9% in the second quarter of 2017 and 2016, respectively.  This decrease in production tax rates as a percentage of oil and natural gas sales is due to a change in sales mix.  Production taxes on natural gas and NGL sales are at a lower percentage than that of crude oil sales.  Crude oil sales represented 90% of oil and natural gas sales in the second quarter of 2017 compared to 96% in the second quarter of 2016.

General and Administrative Expense

General and administrative expenses were $4.3 million in the second quarter of 2017 compared to $4.6 million in the second quarter of 2016.  The decrease was due to a $1.3 million reduction in compensation expenses, primarily driven by a decrease in incentive compensation and lower non-cash share-based compensation expense, partially offset by a $1.0 million increase in legal and other professional fees.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion ("DD&A") was $13.7 million in the second quarter of 2017 compared to $16.2 million in the second quarter of 2016.  Depletion expense, the largest component of DD&A, decreased by $2.5 million in the second quarter of 2017 compared to the second quarter of 2016.  The aggregate decrease in depletion expense was driven by a 15% decrease in the depletion rate per Boe, as well as a 1% decrease in production levels. On a per unit basis, depletion expense was $10.76 per Boe in the second quarter of 2017 compared to $12.64 per Boe in the second quarter of 2016.  The 2017 depletion rate per Boe was lower due to the impairment of oil and natural gas properties in 2016, which lowered the depletable base.  Depreciation, amortization and accretion was $0.2 million and $0.2 million in the second quarter of 2017 and 2016, respectively.

Impairment of Oil and Natural Gas Properties

No impairment of oil and natural gas properties was recorded in the second quarter of 2017.  As a result of low prevailing commodity prices and their effect on the proved reserve values of its properties, Northern recorded a non-cash ceiling test impairment of $88.9 million for the second quarter of 2016.  The impairment charge affected Northern's reported net income in 2016 but did not reduce cash flow.

Interest Expense

Interest expense, net of capitalized interest, was $16.4 million for the second quarter of 2017 compared to $16.0 million in the second quarter of 2016.  The increase in interest expense for the second quarter of 2017 compared to the second quarter of 2016 was primarily due to higher levels of debt between periods.

Income Tax Provision

During the second quarter of 2017 and 2016, no income tax expense (benefit) was recorded on the income (loss) before income taxes due to the valuation allowance placed on the net deferred tax asset.

Non-GAAP Financial Measures

Adjusted Net Income (Loss) for the second quarter of 2017 was a loss of $0.2 million (representing approximately $0.00 per diluted share), compared to income of $6.5 million (representing approximately $0.10 per diluted share) for the second quarter of 2016.  The decrease in Adjusted Net Income (Loss) is primarily due to lower realized commodity prices (after the effect of settled derivatives) and lower production levels.  Northern defines Adjusted Net Income (Loss) as net income (loss) excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax, (ii) impairment of oil and natural gas properties, net of tax, and (iii) write-off of debt issuance costs, net of tax.

Adjusted EBITDA for the second quarter of 2017 was $30.7 million, compared to Adjusted EBITDA of $44.3 million for the second quarter of 2016.  The decrease in Adjusted EBITDA is primarily due to lower realized commodity prices (after the effect of settled derivatives) and lower production levels.  Northern defines Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization and accretion, (iv) (gain) loss on the mark-to-market of derivative instruments, (v) non-cash share based compensation expense, (vi) write-off of debt issuance costs and (vii) impairment of oil and natural gas properties. 

Adjusted Net Income and Adjusted EBITDA are non-GAAP measures.  A reconciliation of these measures to the most directly comparable GAAP measure is included in the accompanying financial tables found later in this release.  Management believes the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of current financial performance.  Specifically, management believes the non-GAAP results included herein provide useful information to both management and investors by excluding certain expenses and unrealized derivatives gains and losses that management believes are not indicative of Northern's core operating results.  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.

SECOND QUARTER 2017 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 Wednesday, August 9, 2017 at 9:00 a.m. Central Time.

Those wishing to listen to the conference call may do so via the company's website, www.northernoil.com, or by phone as follows:

Dial-In Number:  (855) 638-5677 (US/Canada) and (262) 912-4762 (International)
Conference ID:  61127013 - Northern Oil and Gas, Inc. Second Quarter 2017 Conference Call
Replay Dial-In Number: (855) 859-2056 (US/Canada) and (404) 537-3406 (International)
Replay Access Code:  61127013 - Replay will be available through August 16, 2017

UPCOMING CONFERENCE SCHEDULE

EnerCom's The Oil & Gas Conference 22
     August 13 - 17, 2017, Denver, CO

6th Annual Intellisight Conference
     August 22 - 23, 2017, Minneapolis, MN

ABOUT NORTHERN OIL AND GAS

Northern Oil and Gas, Inc. is an exploration and production company with a core area of focus in the Williston Basin Bakken and Three Forks play in North Dakota and Montana.

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, 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 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, Northern's ability to acquire additional development opportunities, changes in Northern's reserves estimates or the value thereof, 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, financial or political instability, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting Northern's operations, products, services 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.

CONTACT:

Brandon Elliott, CFA
Executive Vice President,
  Corporate Development and Strategy
952-476-9800
belliott@northernoil.com

 

CONDENSED STATEMENTS OF OPERATIONS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017 AND 2016
(UNAUDITED)






Three Months Ended
June 30,


Six Months Ended
June 30,


2017


2016


2017


2016

REVENUES








Oil and Gas Sales

$

48,381,006



$

42,527,847



$

97,229,228



$

70,895,188


Gain on Derivative Instruments, Net

16,513,032



(10,522,948)



33,473,915



(7,059,066)


Other Revenue

7,844



9,327



15,590



14,339


Total Revenues

64,901,882



32,014,226



130,718,733



63,850,461










OPERATING EXPENSES








Production Expenses

12,137,540



11,081,973



23,811,889



23,041,232


Production Taxes

4,439,774



4,220,712



8,901,040



6,987,612


General and Administrative Expenses

4,317,139



4,586,275



7,926,083



8,923,677


Depletion, Depreciation, Amortization and Accretion

13,682,452



16,176,863



26,510,595



34,022,952


Impairment of Oil and Natural Gas Properties



88,880,921





193,192,043


Total Expenses

34,576,905



124,946,744



67,149,607



266,167,516










INCOME (LOSS) FROM OPERATIONS

30,324,977



(92,932,518)



63,569,126



(202,317,055)










OTHER INCOME (EXPENSE)








Interest Expense, Net of Capitalization

(16,428,164)



(16,046,325)



(32,731,970)



(32,145,007)


Write-off of Debt Issuance Costs

(95,135)





(95,135)



(1,089,507)


Other Income

181



181



361



7,154


Total Other Income (Expense)

(16,523,118)



(16,046,144)



(32,826,744)



(33,227,360)










INCOME (LOSS) BEFORE INCOME TAXES

13,801,859



(108,978,662)



30,742,382



(235,544,415)










INCOME TAX BENEFIT
















NET INCOME (LOSS)

$

13,801,859



$

(108,978,662)



$

30,742,382



$

(235,544,415)










Net Income (Loss) Per Common Share - Basic

$

0.22



$

(1.78)



$

0.50



$

(3.86)


Net Income (Loss) Per Common Share - Diluted

$

0.22



$

(1.78)



$

0.50



$

(3.86)


Weighted Average Shares Outstanding - Basic

61,643,862



61,180,313



61,545,555



61,071,948


Weighted Average Shares Outstanding - Diluted

61,885,952



61,180,313



61,928,799



61,071,948


 

CONDENSED BALANCE SHEETS
JUNE 30, 2017 AND DECEMBER 31, 2016






June 30, 2017 (unaudited)


December 31, 2016

ASSETS




Current Assets:




Cash and Cash Equivalents

$

3,808,829



$

6,486,098


Accounts Receivable, Net

35,984,651



35,840,042


Advances to Operators

1,631,987



1,577,204


Prepaid and Other Expenses

2,905,975



1,584,129


Derivative Instruments

14,935,836



4,517


 Income Tax Receivable

1,402,179



1,402,179


Total Current Assets

60,669,457



46,894,169






Property and Equipment:




Oil and Natural Gas Properties, Full Cost Method of Accounting




Proved

2,487,266,816



2,428,595,048


Unproved

1,939,789



2,623,802


Other Property and Equipment

977,349



977,349


Total Property and Equipment

2,490,183,954



2,432,196,199


Less - Accumulated Depreciation, Depletion and Impairment

(2,082,243,816)



(2,055,987,766)


Total Property and Equipment, Net

407,940,138



376,208,433






Derivative Instruments

4,557,331




Deferred Income Taxes (Note 9)




Other Noncurrent Assets, Net

8,138,977



8,430,359






Total Assets

$

481,305,903



$

431,532,961






LIABILITIES AND STOCKHOLDERS' DEFICIT

Current Liabilities:




Accounts Payable

$

72,396,006



$

56,146,847


Accrued Expenses

5,772,668



6,094,938


Accrued Interest

4,666,667



4,682,894


Derivative Instruments



10,001,564


Asset Retirement Obligations

507,943



517,423


Total Current Liabilities

83,343,284



77,443,666






Long-term Debt, Net

845,281,659



832,625,125


Derivative Instruments



1,738,329


Asset Retirement Obligations

8,005,619



6,990,877


Other Noncurrent Liabilities

146,313



156,632






Total Liabilities

$

936,776,875



$

918,954,629






Commitments and Contingencies (Note 8)








STOCKHOLDERS' DEFICIT




Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding




Common Stock, Par Value $.001; 142,500,000 Authorized (6/30/2017 - 63,822,028
Shares Outstanding and 12/31/2016 - 63,259,781 Shares Outstanding)

63,822



63,260


Additional Paid-In Capital

445,102,784



443,895,032


Retained Deficit

(900,637,578)



(931,379,960)


Total Stockholders' Deficit

(455,470,972)



(487,421,668)


TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT

$

481,305,903



$

431,532,961


 

Reconciliation of Adjusted Net Income






Three Months Ended June 30,


Six Months Ended June 30,


2017


2016


2017


2016

Net Income (Loss)

$

13,801,859



$

(108,978,662)



$

30,742,382



$

(235,544,415)


Add:








Impact of Selected Items:








(Gain) Loss on the Mark-to-Market of Derivative Instruments

(14,172,002)



30,506,698



(31,228,544)



52,489,716


Write-off of Debt Issuance Costs

95,135





95,135



1,089,507


Impairment of Oil and Natural Gas Properties



88,880,921





193,192,043


Selected Items, Before Income Taxes

(14,076,867)



119,387,619



(31,133,409)



246,771,266


Income Tax of Selected Items(1)

99,518



(3,899,825)



159,429



(4,112,781)


Selected Items, Net of Income Taxes

(13,977,349)



115,487,794



(30,973,980)



242,658,485


Adjusted Net Income (Loss)

$

(175,490)



$

6,509,132



$

(231,598)



$

7,114,070










Weighted Average Shares Outstanding - Basic

61,643,862



61,180,313



61,545,555



61,071,948


Weighted Average Shares Outstanding - Diluted

61,885,952



62,079,083



61,928,799



61,361,831










Net Income (Loss) Per Common Share - Basic

$

0.22



$

(1.78)



$

0.50



$

(3.86)


Add:








Impact of Selected Items, Net of Income Taxes

(0.22)



1.89



(0.50)



3.97


Adjusted Net Income (Loss) Per Common Share - Basic

$



$

0.11



$



$

0.11










Net Income (Loss) Per Common Share - Diluted

$

0.22



$

(1.76)



$

0.50



$

(3.84)


Add:








Impact of Selected Items, Net of Income Taxes

(0.22)



1.86



(0.50)



3.95


Adjusted Net Income (Loss) Per Common Share - Diluted

$



$

0.10



$



$

0.11










______________

(1)

For the 2017 columns, this represents a tax impact using an estimated tax rate of 37.1% and 37.8% for the three and six months ended June 30, 2017, respectively, which includes a $5.1 million and $11.6 million adjustment for a reduction in valuation allowance for the three and six months ended June 30, 2017, respectively.  For the 2016 columns, this represents a tax impact using an estimated tax rate of 37.5% and 36.6% for the three and six months ended June 30, 2016, respectively, which includes a $40.8 million and $86.3 million adjustment for a change in valuation allowance for the three and six months ended June 30, 2016, respectively.

 

Reconciliation of Adjusted EBITDA






Three Months Ended June 30,


Six Months Ended June 30,


2017


2016


2017


2016

Net Income (Loss)

$

13,801,859



$

(108,978,662)



$

30,742,382



$

(235,544,415)


Add:








Interest Expense

16,428,164



16,046,325



32,731,970



32,145,007


Income Tax Benefit








Depreciation, Depletion, Amortization and Accretion

13,682,452



16,176,863



26,510,595



34,022,952


Impairment of Oil and Natural Gas Properties



88,880,921





193,192,043


Non-Cash Share Based Compensation

910,737



1,629,677



1,533,359



3,021,470


Write-off of Debt Issuance Costs

95,135





95,135



1,089,507


(Gain) Loss on the Mark-to-Market of Derivative Instruments

(14,172,002)



30,506,698



(31,228,544)



52,489,716


Adjusted EBITDA

$

30,746,345



$

44,261,822



$

60,384,897



$

80,416,280


 

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