VINE ENERGY INC.
The following should be read in conjunction with our financial statements and
related notes appearing elsewhere in this Quarterly Report on Form
10-Q
("Quarterly Report"). The following discussion contains "forward-looking
statements" that reflect our future plans, estimates, beliefs and expectations.
We caution that assumptions, expectations, projections, intentions or beliefs
about future events may vary materially from actual results. Some of the key
factors that could cause actual results to vary from our expectations include
those factors discussed below and elsewhere in this Quarterly Report, all of
which are difficult to predict. In light of these risks, uncertainties and
assumptions, the forward-looking events discussed may not occur. "Cautionary
Statement Regarding Forward- Looking Statements" and "Risk Factors" (included in
the Company's final prospectus, dated March 17, 2021 , filed with the Securities
and Exchange Commission ("SEC") pursuant to Rule 424(b)(4) of the Securities Act
of 1933, as supplemented, the "Registration Statement") contain important
information. We do not undertake any obligation to publicly update any
forward-looking statements except as otherwise required by applicable law.
Unless otherwise indicated, the historical financial information as of and for
the three and six months ended June 30, 2020 presented in "Management's
Discussion and Analysis of Financial Condition and Results of Operations" speaks
only with respect to our Predecessor and does not give pro forma effect to our
corporate reorganization described in "Factors That Significantly Affect
Comparability of Our Financial Condition and Results of Operations-Corporate
Reorganization."
Investors are cautioned that the forward-looking statements contained in this
section and other parts of this Quarterly Report involve both risk and
uncertainty. Several important factors could cause actual results to differ
materially from those anticipated by these statements. Many of these statements
are macroeconomic in nature and are, therefore, beyond the control of
management. See "Cautionary Statement Regarding Forward-Looking Statements"
above and the Company's Registration Statement.
Overview
We are a pure play natural gas company focused solely on the development of
natural gas properties in the stacked Haynesville and
Mid-Bossier
shale plays in the Haynesville Basin of Northwest Louisiana . As of December 31,
2020 , on a pro forma basis, we had approximately 125,000 net surface acres
centered in what we believe to be the core of the Haynesville and
Mid-Bossier
plays. Over 90% of our acreage is held by production, and we operate over 90% of
our future drilling locations. As of December 31, 2020 , on a pro forma basis, we
had approximately 370 net producing wells. Our assets are located almost
entirely in Red River , DeSoto and Sabine parishes of Northwest Louisiana , which
according to Enverus, have consistently demonstrated higher EURs relative to D&C
costs than the Haynesville and
Mid-Bossier
plays in Texas and other parishes in Louisiana . Approximately 84% of our acreage
is prospective for dual-zone development, providing us with approximately 900
drilling locations. Utilizing an average of 4 gross rigs, we have approximately
25 years of development opportunities.
Market Conditions and Operational Trends
The oil and gas industry is cyclical and commodity prices are highly volatile.
Spot prices for Henry Hub generally ranged from $1.50 per MMBtu to $4.75 per
MMBtu since the Company's inception in 2014. We expect that this market will
continue to be volatile in the future. The prices we receive for our production,
and the levels of our production, depend on numerous factors beyond our control.
We use our derivative portfolio and firm sales contracts to mitigate the risks
of price volatility.
Our new reserve- based lending facility (the "New RBL") and second lien term
loan (as amended, the "Second Lien Term Loan") require that we hedge 70% of our
reasonably anticipated projected production of natural gas from proved developed
producing reserves for the next 24 months. By virtue of this hedging
requirement, we are impacted less by gas price volatility during this time frame
than future periods where a smaller percentage of our production is subject to
derivative contracts. We believe our balance sheet and hedge program provide
ample liquidity in the event of an adverse commodity price environment to enable
us to continue to generate levered free cash flow.
To the extent, however, that natural gas prices decrease, these lower prices not
only reduce our revenue and cash flows, but also may limit the amount of natural
gas that we can develop economically and therefore potentially lower our proved
reserves. Lower commodity prices in the future could also result in impairments
of our natural gas properties. The occurrence of any of the foregoing could
materially and adversely affect our future business, financial condition,
results of operations, operating cash flows, liquidity or ability to fund
planned CapEx. Alternatively, natural gas prices may increase, which while
increasing revenue and cash flows would result in significant losses being
incurred on our derivatives.
We believe domestic gas macro fundamentals are positively disposed in the
near-to-intermediate
term as continued lower
oil-focused
drilling activity will lead to lower associated gas production resulting in a
tighter market and higher prices than current levels as well as increased LNG
feedstock and exports to Mexico .
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Additionally, the oil and gas industry is subject to a number of operational
trends, some of which are particularly prominent in the Haynesville Basin , where
companies are increasingly utilizing new techniques to lower D&C costs per
lateral foot and enhance new well economics, including using more proppant and
water per lateral foot, increasing use of longer laterals and increased
automation to reduce drilling time and costs.
Evaluating Our Operations
We use the following metrics to assess the performance of our natural gas
operations:
• reserve and production levels;
• realized prices on the sale of our production, including derivative effects;
• lease operating expenses; • Adjusted EBITDAX; and
• D&C costs per well and per lateral foot drilled and overall CapEx levels.
Production Levels and Sources of Revenue We derive our revenue from the sale of our natural gas production and sales volumes directly impact our results of operations. As reservoir pressures decline with a well's age, production from a given well decreases. Growth in our future production and reserves will depend on our continued ability to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through organic drill-bit growth as well as opportunistically through acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our gas prices, capital availability, regulatory approvals and ability to procure equipment, services and personnel and successfully execute the development program or acquisitions. Increases or decreases in our future production, revenue and profitability are highly dependent on the commodity prices we receive. Natural gas prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors. We believe that higher volumes of natural gas will be produced or sold in theGulf Coast region, but we also expect that higher demand from industrial expansion and export growth will cause theGulf Coast markets to stabilize and our differentials to NYMEX will remain close to the current range and significantly better than differentials other basins have experienced. To mitigate the variability in differentials, we have entered into multiple physical firm sales contracts at fixed differentials to NYMEX. Changes in commodity prices are as follows: For the Three Months For the Six Months Ended June 30, Ended June 30 2021 2020 2021 2020 ($ / MMBtu) ($ / MMBtu)NYMEX Henry Hub High (1)$ 2.98 $ 1.79 $ 2.98 $ 2.16 NYMEX Henry Hub Low (1)$ 2.59 $ 1.63 $ 2.47 $ 1.63 Differential to Average NYMEX Henry Hub (2)$ (0.20 ) $ (0.17 ) $ (0.15 ) $ (0.17 )
(1) Represents monthly Henry Hub settlement price.
(2) Our differential is calculated by comparing the average NYMEX Henry Hub price
to our volume weighted average realized price per MMBtu.
We utilize an unaffiliated third party to market a portion of our gas production
to various purchasers, which consist of credit-worthy counterparties, including
utilities, LNG producers, industrial consumers, major corporations and super
majors, in our industry. This third party collects directly from the purchasers
and remits to us the total of all amounts collected on our behalf less their fee
for making such sales. Additionally, we sell the majority of our gas to
purchasers who remit directly to us under single month and firm sales contracts.
We do not believe the loss of any customer would have a material adverse effect
on our business, as other customers or markets are currently accessible to us.
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Adjusted EBITDAX
We believe Adjusted EBITDAX is useful because it makes for easier comparison of
our operating performance, without regard to our financing methods, corporate
form or capital structure. We determined our adjustments from net income to
arrive at Adjusted EBITDAX to reflect the substantial variance in practice from
company to company within our industry depending upon accounting methods and
book values of assets, capital structures and the method by which the assets
were acquired. Adjusted EBITDAX should not be considered more meaningful than
net income determined in accordance with U.S. GAAP. Certain items excluded from
Adjusted EBITDAX are significant components in understanding and assessing a
company's financial performance, such as a company's cost of capital and tax
burden, as well as the historic costs of depreciable assets, none of which are
components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not
be construed as an inference that our results will be unaffected by unusual or
non-recurring
items. Our computations of Adjusted EBITDAX differ from other similarly titled
measures of other companies.
D&C Costs and CapEx
We evaluate our D&C costs by considering the absolute cost to drill and complete
a well and install surface facilities, as well as the cost on a per lateral foot
basis. Moreover, we evaluate the level of reserves developed per dollar spent in
connection with that development to measure our capital efficiency. So long as
these metrics continue to meet our expectations, we expect our overall CapEx
levels to support an average
3-4
gross drilling rig program. Our capital efficiency is one of the key metrics we
use to manage our business.
Factors That Significantly Affect Comparability of Our Financial Condition and
Results of Operations
Our historical financial condition and results of operations for the periods
presented may not be comparable, either from period to period or going forward,
for the following reasons:
Initial Public Offering.
In March 2021 , we completed our initial public offering (the "Offering") of
24,725,000 shares, including the underwriters' option to purchase 3,225,000
additional shares, of the Company's Class A common stock, par value $0.01 per
share ("Class A Common Stock") at a price of $14.00 per share to the public. The
sale of the Company's Class A Common Stock resulted in gross proceeds of
$346.2 million to the Company and net proceeds of $321.0 million , after
deducting underwriting fees and offering expenses. The material terms of the
Offering are described in the Company's Registration Statement.
The Company contributed the net proceeds of the Offering to Vine Holdings in
exchange for newly issued limited liability interests in Vine Holdings ("Vine
Units"). Vine Holdings utilized the proceeds from the Offering to repay all
outstanding borrowings under that certain Senior Secured Credit Agreement dated
as of March 20, 2018 by and among Brix Operating LLC , the lenders from time to
time party thereto, and Macquarie Investments US Inc. , as administrative agent,
as amended from time to time (the "Brix Credit Facility") and Vine Oil & Gas's
revolving credit facility, dated as of November 25, 2014 (the "Prior RBL"), and
to pay fees and expenses related to the Offering and debt issuance costs related
to the repayment of a portion of our indebtedness.
Upon completion of the Offering, we have incurred and expect continued
incurrence of direct, incremental G&A expenses as a result of being publicly
traded, including costs associated with Exchange Act compliance, tax compliance,
PCAOB support fees, SOX compliance costs, investor relations activities, listing
fees, registrar and transfer agent fees, stock-based compensation, incremental
director and officer liability insurance costs and independent director
compensation. We estimate these direct, incremental G&A expenses could total
approximately $10 million to $12 million per year, which are not included in our
historical results of operations. We anticipate these effects will be mitigated
by additional recoveries associated with our expanded operated well count and
the elimination of the monitoring fee.
Corporate Reorganization.
Immediately prior to the Notice of Effectiveness from the SEC on March 17, 2021 ,
Vine Holdings underwent a corporate reorganization ("Corporate Reorganization")
whereby (a) the existing owners who directly held equity interests in Vine Oil &
Gas , Vine Oil & Gas GP, Brix, Brix GP, Harvest and Harvest GP (together, the
"Existing Owners") contributed such equity interests to Vine Holdings in
exchange for newly issued equity in Vine Holdings (the "LLC Interests") to
effectuate a merger of such entities into Vine Holdings , (b) certain of the
Existing Owners contributed a portion of their LLC Interests directly, or
indirectly by contribution of blocker entities (entities that are taxable as
corporations for U.S. federal income tax purposes, the "Blocker Entities")
holding LLC Interests, to the Company in exchange for newly issued Class A
Common Stock and contributed such Class A Common Stock received to Vine
Investment II, Brix Investment II, Harvest Investment II, Vine Investment , Brix
Investment or Harvest Investment , (together, the "Investment Vehicles"), as
applicable, (c) certain of the Existing Owners exchanged the remaining portion
of their LLC Interests for Vine Units and subscribed for newly issued Class B
common stock of the Company ("Class B Common
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Stock") with no economic rights or value and contributed such Vine Units and
Class B Common Stock to Vine Investment , Brix Investment and Harvest Investment ,
as applicable, and (d) the Company contributed the net proceeds of the Offering
to Vine Holdings in exchange for newly issued Vine Units and a managing member
interest in Vine Holdings .
Each share of Class B Common Stock entitles its holder to one vote on all
matters to be voted on by shareholders. Holders of Class A Common Stock and
Class B Common Stock vote together as a single class on all matters presented to
our shareholders for their vote or approval, except as otherwise required by
applicable law or by our certificate of incorporation. The Class B Common Stock
is not listed on any stock exchange.
Holders of Vine Units may surrender such shares, together with the same number
of shares of Class B Common Stock to Vine Holdings in exchange for either (1) a
number of shares of Class A Common Stock equal to the product of such number of
Vine Units surrendered multiplied by a current exchange rate of one for one,
subject to modification under the terms of the Exchange Agreement, dated March
17, 2021 (the "Exchange Agreement"), or (2) at the Company's election, cash
equal to an amount calculated in accordance with the Exchange Agreement. If at
any time, a Vine Unit holder surrenders its Vine Units, an equal number of
Class B Common Stock shares must be concurrently surrendered.
Our historical financial data as of December 31, 2020 and for the three and six
months ended June 30, 2020 , reflects Vine Oil & Gas LP , the accounting
predecessor of Vine Energy Inc. The financial data for the three and six months
ended June 30, 2021 , includes Vine Oil & Gas LP for the entire period and the
Brix Companies from March 17, 2021 , the effective date of the acquisition as a
result of the Corporate Reorganization. Accordingly, the financial information
for the three and six months ended June 30, 2021 may not yield an accurate
indication of what our actual results would have been if the Offering and the
Corporate Reorganization had been completed at the beginning of the period
presented or of what our future results of operations are likely to be in the
future.
Monitoring fee.
Monitoring fees were paid pursuant to a management and consulting agreement with
Blackstone and our CEO, of which over 99% is attributable to Blackstone . The
monitoring fee was eliminated upon completion of the Offering.
Interest Expense.
In connection with the Offering and Bond Refinancing (as defined below), we
materially reduced our indebtedness and, therefore, we had an immediate
reduction in cash interest expense and could see further reductions in cash
interest expense as we use free cash flow to lower our debt.
Income Taxes.
Our Predecessor was a limited partnership not subject to federal income taxes.
Accordingly, no provision for federal income taxes has been provided for in our
historical results of operations because taxable income was passed through to
our partners. We are taxed as a corporation under the Internal Revenue Code and
subject to U.S. federal income tax at the statutory rate of pretax earnings.
Accordingly, the amount of our future U.S. federal income tax will be dependent
upon our future taxable income. Additionally, the Company is subject to state
income tax in multiple jurisdictions.
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Results of Operations
For the Three Months Ended June 30, For the Six Months Ended June 30,
2021 2020 2021 2020
(in thousands, except per Mcf) (in thousands, except per Mcf)
Production:
Total (MMcf) 95,561 59,441 160,699 116,087
Average Daily (MMcfd) 1,050 653 888 638
Revenue: Per Mcf Per Mcf Per Mcf Per Mcf
Natural gas sales $ 233,851 $ 2.45 $ 84,116 $ 1.42 $ 387,837 $ 2.41 $ 176,659 $ 1.52
Realized gain on commodity
derivatives (24,022 ) (0.25 ) 45,686 0.77 (24,782 ) (0.15 ) 87,730 0.76
Unrealized (loss) gain on commodity
derivatives (274,279 ) (2.87 ) (58,727 ) (0.99 ) (309,382 ) (1.93 ) (63,366 ) (0.55 )
Total revenue (64,450 ) (0.67 ) 71,075 1.20 53,673 0.33 201,023 1.73
Operating Expenses:
Lease operating 16,522 0.17 11,477 0.19 31,482 0.20 24,472 0.21
Gathering and treating 28,750 0.30 20,387 0.34 49,351 0.31 36,769 0.32
Production and ad valorem taxes 6,018 0.06 4,286 0.07 10,000 0.06 8,435 0.07
General and administrative 4,772 0.05 1,349 0.02 7,355 0.05 4,680 0.04
Monitoring fee - - 1,787 0.03 2,077 0.01 3,525 0.03
Stock-based compensation related to
Offering 13,665 0.14 - - 13,665 0.09 - -
Depreciation, depletion and accretion 125,125 1.31 85,610 1.44 222,197 1.38 167,934 1.45 Exploration 89 0.00 60 0.00 89 0.00 135 0.00 Strategic - - 1,551 0.03 - - 2,113 0.02 Severance - - 326 0.01 - - 326 0.00 Write-off of deferred offering costs - - - - - - 5,787 0.05 Total operating expenses 194,941 2.04 126,833 2.13 336,216 2.09 254,176 2.19 Operating income (259,391 ) (55,758 ) (282,543 ) (53,153 ) Interest expense (96,406 ) (28,713 ) (131,081 ) (58,064 ) Income tax provision (4,455 ) (100 ) (4,620 ) (250 ) Total other expenses (100,861 ) (28,813 ) (135,701 ) (58,314 ) Net income$ (360,252 ) $ (84,571 ) $ (418,244 ) $ (111,467 ) Interest expense 96,406 28,713 131,081 58,064 Income tax provision 4,455 100 4,620 250 Depreciation, depletion and accretion 125,125 85,610 222,197 167,934 Unrealized loss on commodity derivatives 274,279 58,727 309,382 63,366 Exploration 89 60 89 135 Non-cash G&A 98 4 97 (2 ) Non-cash stock compensation to Existing Management Owners 13,665 - 13,665 - Strategic - 1,551 - 2,113 Severance - 326 - 326 Non-cash write-off of deferred IPO costs - - - 5,787 Non-cash volumetric and production adjustment to gas gathering liability - - - (2,567 ) Adjusted EBITDAX$ 153,865 $ 90,520 $ 262,887 $ 183,939 31
-------------------------------------------------------------------------------- Table of Contents Revenue Natural Gas Sales and Realized Commodity Derivatives The changes in our natural gas sales and realized derivative effects are as follows (in thousands): Three months endedJune 30, 2020 $ 129,802 Volume 51,114 Price 98,621 Realized derivative (69,708 )
Three months ended
Six months endedJune 30, 2020 $ 264,389 Volume 67,890 Price 143,288 Realized derivative (112,512 )
Six months ended
The increase in natural gas volume for the three months and six months endedJune 30, 2021 was primarily the result of new wells and additional production attributable to the Brix Companies since the Corporate Reorganization. The price increase for the three months endedJune 30, 2021 was driven by the increase in the Henry Hub price upon which our sales price is generally determined. Since commodity prices were above the weighted average floor prices of our derivative portfolio, we realized a net loss on our natural gas derivatives during the three and six months endedJune 30, 2021 . Conversely, commodity prices were below the weighted average floor prices of our derivative portfolio for the three and six months endedJune 30, 2020 , and we realized a net gain on our natural gas derivatives. The average prices of natural gas in our commodity derivative contracts for the three and six months endedJune 30, 2021 were approximately$2.52 and$2.62 per MMBtu, respectively. The average prices of natural gas in our commodity derivative contracts for the three and six months endedJune 30, 2020 were approximately$2.64 and$2.72 per MMBtu, respectively. Additionally, our total volumes hedged for the three and six months endedJune 30, 2021 were approximately 86% and 90% of net gas produced, respectively. Additionally, our total volumes hedged for the three and six months endedJune 30, 2020 were approximately 88% and 91% of net gas produced, respectively. As our production volumes fluctuate, we would expect our revenue to also fluctuate, depending on prevailing natural gas prices and the extent of our hedges. Unrealized Loss on Commodity Derivatives We had an unrealized loss on our commodity derivative contracts for all 2021 and 2020 periods presented, which was primarily related to increases in NYMEX natural gas futures relative toDecember 31, 2020 and 2019, respectively. Operating Expenses Lease Operating ("LOE")LOE for the three months endedJune 30, 2021 increased$5.0 million compared to the three months endedJune 20, 2020 but was down$0.02 on a per Mcf basis. The increase in LOE on an absolute basis was primarily due to the addition of the Brix Companies since the Corporate Reorganization as well as new wells brought online. LOE is down on per Mcf basis due to a decline in water disposal costs arising from our comprehensive multi-year water management plan. LOE for the six months endedJune 30, 2021 increased$7.0 million compared to the three months endedJune 20, 2020 but was down$0.01 on a per Mcf basis. The increase in LOE on an absolute basis was primarily due to the addition of the Brix Companies since the Corporate Reorganization as well as new wells brought online. LOE is down on per Mcf basis due to reduced water disposal costs offset by an increase in expenses due to winter storm Uri in the first quarter of 2021. The storm caused additional expenses in labor, water disposal and equipment repairs to restore production. 32 -------------------------------------------------------------------------------- Table of Contents We expect that our LOE will increase in the future as additional wells are brought online but may decrease on a unit cost basis as production increases since a portion of our LOE is fixed. Gathering and Treating For the Three Months Ended June 30, For the Six Months Ended June 30, 2021 2020 2021 2020 (in thousands) Per Mcf (in thousands) Per Mcf (in thousands) Per Mcf (in thousands) Per Mcf Gathering - Cash $ 27,674$ 0.29 $ 20,195$ 0.34 $ 48,009$ 0.30 $ 38,923$ 0.34 Gathering - Non-Cash - - - - - - (2,567 ) (0.02 ) Other 1,076 0.01 192 0.00 1,342 0.01 413 - Total $ 28,750$ 0.30 $ 20,387$ 0.34 $ 49,351$ 0.31 $ 36,769$ 0.32 Gathering and treating expense increased in the three months endedJune 30, 2021 on an absolute basis but was down$0.04 per Mcf on a unit cost basis due to a contractual gathering rate decrease that occurred in the fourth quarter of 2020 as well as lower gathering rates on the legacy wells of the Brix Companies. Gathering and treating expense increased in the six months endedJune 30, 2021 on an absolute basis but was down$0.01 per Mcf on a unit cost basis due to a contractual gathering rate decrease that occurred in the fourth quarter of 2020 as well as lower gathering rates on the legacy wells of the Brix Companies. Our non-cash gathering liability gain decreased as all obligations under the gathering liability were satisfied in 2020 with no payments required in 2020 or 2021 on our minimum volume gathering commitment. We expect gathering and treating expense per Mcf to be in the range of$0.29 to$0.30 per Mcf for the remainder of 2021. Production and Ad Valorem Taxes For the Three Months Ended June 30, For the Six Months Ended June 30, 2021 2020 2021 2020 (in thousands) Per Mcf (in thousands) Per Mcf (in thousands) Per Mcf (in thousands) Per Mcf Production taxes $ 4,211$ 0.04 $ 2,871$ 0.05 $ 6,576$ 0.04 $ 5,604$ 0.05 Ad valorem taxes 1,807 0.02 1,415 0.02 3,424 0.02 2,831 0.02 Total $ 6,018$ 0.06 $ 4,286$ 0.07 $ 10,000$ 0.06 $ 8,435$ 0.07 For the three and six months endedJune 30, 2021 , production and ad valorem taxes increased on an absolute basis due to the addition of the Brix Companies since the Corporate Reorganization. Although higher natural gas prices have caused our wells to payout faster thereby losing production tax exemptions, production taxes were relatively flat on a unit cost basis because the state ofLouisiana dropped the severance tax rate from$0.125 per Mcf to$0.0934 per Mcf in the third quarter of 2020. We expect our production and ad valorem tax to increase in the future as we develop our assets and increase the number of producing wells on which such taxes are levied. We expect these new wells will continue to qualify for early life production tax exemptions, and we expect our production tax costs will increase in absolute terms as wells meet payout and are no longer production tax exempt. Production taxes are paid on produced natural gas based on rates established annually by the state ofLouisiana . 33 -------------------------------------------------------------------------------- Table of Contents G&A For the Three Months Ended For the Six Months Ended June 30, June 30, 2021 2020 2021 2020 (in thousands) (in thousands) Wages and benefits$ 7,081 $ 5,947 $ 13,304 $ 13,009 Professional services 1,256 660 2,347 1,689 Licenses, fees and other 1,517 1,699 3,259 3,764 Total gross G&A expense 9,854 8,306 18,910 18,462
Less:
Allocations to affiliates - (2,248 ) (1,748 ) (4,517 ) Recoveries (5,082 ) (4,709 ) (9,807 ) (9,265 ) Net G&A expense$ 4,772 $ 1,349 $ 7,355 $ 4,680 Gross G&A expense for the three and six months endedJune 30, 2021 increased primarily due to increased professional services associated with being a public company. We had lower allocations to affiliates due to the elimination of allocations effective with the date of the Corporate Reorganization. Our net G&A expense was reduced by higher recoveries in the 2021 periods presented attributable to inclusion of the Brix Companies recoveries since the Corporate Reorganization and increased producing well count. Stock Compensation to Existing Management Owners OnJune 15, 2021 ,Blackstone and management calculated the final conversion of the Class A, B, and C units that were previously held at our Predecessor and the Brix Companies into a single class of equity inVine Investment ,Brix Investment ,Harvest Investment , Vine Investment II, Brix Investment II and Harvest Investment II. The Class A and C Units of our Predecessor, Brix and Harvest were deemed modified effectiveJune 15, 2021 . As a result, we recorded non-cash stock compensation expense of$13.7 million in the second quarter of 2021. Write-off of Deferred Offering Costs In conjunction with a possible initial public offering, costs incurred related to such an offering, including legal, audit, tax and other professional services are capitalized as deferred equity issuance costs. In the first quarter of 2020, we wrote-off deferred offering costs related to years that would no longer be presented in any future potential filings. Beginning in the fourth quarter of 2020, we incurred costs related to the Offering that occurred in the first quarter of 2021 that were offset against Offering proceeds. Monitoring Fee The management and consulting agreement withBlackstone and our CEO was eliminated effective with the Offering thereby causing the reduction in monitoring fees for the three and six months endedJune 30, 2021 . DD&A For the Three Months Ended June 30, For the Six Months Ended June 30, 2021 2020 2021 2020 (in thousands) Per Mcf
(in thousands) Per Mcf (in thousands) Per Mcf (in
Per Mcf
Depletion $ 123,402 $ 1.29 $ 84,008 $ 1.41 $ 218,918 $ 1.36 $ 164,067 $ 1.41
Depreciation 1,329 0.01 1,269 0.02 2,524 0.02 2,689 0.02
Accretion 394 0.00 333 0.01 755 0.00 1,178 0.01
Total $ 125,125 $ 1.31 $ 85,610 $ 1.44 $ 222,197 $ 1.38 $ 167,934 $ 1.45
34-------------------------------------------------------------------------------- Table of Contents The increase in DD&A for the three and six months endedJune 30, 2021 was due to increased production on new wells along with production added from the Brix Companies since the date of the Corporate Reorganization. The per MCF decrease in depletion expense for the three and six months endedJune 30, 2021 is due to a lower depletion rate related to the Corporate Reorganization and fair value of the Brix Companies' assets acquired. We expect our depletion rate will fluctuate in the future based on levels of CapEx incurred to develop our assets and changes in proved reserve levels. Depreciation increased for the three months endedJune 30, 2021 related to new saltwater disposal wells. The decrease in deprecation for the six months endedJune 30, 2021 was primarily associated with some assets becoming fully depreciated offset by an increase for depreciation on new saltwater disposal wells. The decrease in accretion expense for the six months endedJune 30, 2021 was related to the elimination of our gas gathering liability in the first quarter of 2021. Interest Expense For the Three Months Ended June 30, For the Six Months Ended June 30, 2021 2020 2021 2020 (in thousands) Cash interest: Interest costs on debt outstanding $ 20,836 $
23,876 $ 47,007
62,573 - 62,573 -
Letter of credit and other fees 375 396 974 770
Total cash interest 83,784 24,272 110,554 49,262
Non-cash
interest:
Non-cash
interest on debt outstanding 2,106 4,441 5,129 8,802
Non-cash
loss on extinguishment of debt 10,516 - 15,398 - Total non-cash interest 12,622 4,441 20,527 8,802 Total interest expense $ 96,406 $ 28,713 $ 131,081$ 58,064 The decrease in cash interest costs on debt outstanding for the three and six months endedJune 30, 2021 was associated with lower debt outstanding and overall lower interest rates with our new debt structure. Non-cash interest on debt outstanding includes reduced amortization of deferred financing costs due to the debt transactions associated with the Offering and issuance of the 6.75% Notes. The cash redemption premiums on extinguishment of debt was paid for the early termination of the 8.75% Notes and 9.75% Notes inApril 2021 . The loss on extinguishment of debt was associated with the write-off of deferred financing costs and debt discount associated with the termination of the 8.75% Notes, the 9.75% Notes, the Prior RBL and Third Lien facility. Capital Resources and Liquidity Our development activities require us to make significant operating and capital expenditures. Our primary use of capital has historically been for the development of natural gas properties. In addition, we regularly evaluate our capital structure and opportunities to manage our liabilities, as well as other strategic transactions that we believe to be credit accretive. Contemporaneously with the closing of the Offering, we entered into the New RBL to repay in full and terminate each of the Prior RBL and the Brix Credit Facility. The New RBL has a total facility size of$750 million and a borrowing base of$350 million . As ofJune 30, 2021 , we had$35 million drawn on our RBL and available capacity of$302 million (after giving effect to$13 million of letters of credit). InApril 2021 ,Vine Holdings completed its offering of$950 million aggregate principal amount of 6.75% senior unsecured notes due 2029 (the "6.75% Notes"). The net proceeds from the Bond Offering, along with cash on hand, were used to redeem all the 8.75% Notes and 9.75% Notes. We expect our 2021 pro forma capital program to be in the range of$340 to$350 million . We expect to fund our 2021 CapEx largely through operating cash flow and to a limited extent with borrowings under our New RBL, while maintaining considerable liquidity and financial flexibility. 35 -------------------------------------------------------------------------------- Table of Contents We believe that operating cash flow and our available capacity under our New RBL should be sufficient to fully fund our forecasted CapEx for 2021 and meet our cash requirements, including normal operating needs, debt service obligations and commitments and contingencies. However, we may access the capital markets to raise capital to the extent that we consider market conditions favorable. Cash Flow Activity Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices that we realize for our natural gas and the volumes of natural gas that we produce. Natural gas is a commodity for which established trading markets exist. Accordingly, our operating cash flow is sensitive to a number of variables, the most significant of which are the volatility of natural gas prices and production levels both regionally and acrossNorth America , the availability and price of alternative fuels, infrastructure capacity to reach markets, costs of operations and other variable factors. We monitor factors that we believe could be likely to influence price movements including new or expanded natural gas markets, gas imports, LNG and other exports and industry CapEx levels. The Company's cash flow activity is as follows (in thousands): For the Six Months Ended June 30, 2021 2020 Operating cash flow 206,020$ 136,254 Investing cash flow (151,529 ) (161,903 ) Financing cash flow (15,020 ) 70,780 Net change in cash $ 39,471 $ 45,131 2021 Compared to 2020 Operating Cash Flow Our cash flow provided by operating activities for the six months endedJune 30, 2021 was higher primarily due to higher natural gas sales driven by increased production and price. Investing Cash Flow Our cash flow used by investing activities for the six months endedJune 30, 2021 decreased due to$19.9 million of cash received from the acquisition of the Brix Companies, partially offset by higher capital expenditures due to the inclusion of the Brix Companies Capex subsequent to the Corporate Reorganization. Financing Cash Flow Our financing cash flow for the six months endedJune 30, 2021 decreased primarily due to cash redemption premiums paid of$62.6 million to repay the 8.75% Notes and the 9.75% Notes prior to maturity and the payment of$28.7 million of deferring financing costs associated with replacing our RBL and issuing the 6.75% Notes. 36 -------------------------------------------------------------------------------- Table of Contents Derivative Activities Our commodity derivatives allow us to mitigate the potential effects of the variability in operating cash flow thereby providing increased certainty of cash flows to support our capital program and to service our debt. We believe our New RBL affords us greater flexibility to hedge than similar agreements of our peers because it allows us to hedge a large percentage of our total expected production. Typically, credit documents limit borrowers to hedging only production from already developed reserves. Our New RBL and Second Lien Term Loan require that we hedge 70% of our reasonably anticipated projected production of natural gas from proved developed producing reserves for the next 24 months. Our derivatives provide only partial price protection against declines in natural gas prices and partially limit our potential gains from future increases in prices. Our current derivative portfolio cannot protect us from the risk of a potential widening of differentials between our sales price and NYMEX. The Company's outstanding derivative positions as ofJune 30, 2021 are as follows: Natural Gas Swaps Natural Gas Weighted Average Volumes Swap Price Period (MMBtud) ($ / MMBtu) 2021 Third Quarter 845,333 $ 2.53 Fourth Quarter 848,887 $ 2.62 2022 First Quarter 866,797 $ 2.56 Second Quarter 348,859 $ 2.54 Third Quarter 409,853 $ 2.54 Fourth Quarter 604,935 $ 2.53 2023 First Quarter 528,652 $ 2.48 Second Quarter 65,470 $ 2.45 Third Quarter 45,954 $ 2.44 Fourth Quarter 125,092 $ 2.50 2024 First Quarter 313,512 $ 2.53 Second Quarter 11,957 $ 2.31 Third Quarter 7,366 $ 2.31 Fourth Quarter 70,761 $ 2.58 2025 First Quarter 137,667 $ 2.58 37
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Sold Natural Gas Calls
Weighted Average
Natural Gas Call Price
Volumes
Production Year (MMBtud) ($ / MMBtu)
2021
Third Quarter (30,000 ) $ 2.85
2022
Second Quarter (8,352 ) $ 3.02
2023
First Quarter (180,000 ) $ 3.26
Sold Natural Gas Puts
Weighted Average
Natural Gas Put Price
Volumes
Production Year (MMBtud) ($ / MMBtu)
2021
Third Quarter 30,000 $ 2.55
2022
Second Quarter 8,352 $ 2.80
Basis swaps
Weighted Average
Natural Gas Basis Swap
Volumes
Production Year (MMBtud) ($ / MMBtu)
2022
First Quarter 62,500 $ (0.19 )
Second Quarter 62,500 $ (0.19 )
Third Quarter 62,500 $ (0.19 )
Fourth Quarter 62,500 $ (0.19 )
We expect to continue to use commodity derivatives to hedge our price risk in the future, though the notional and pricing levels will be dependent upon prevailing conditions, including available capacity of our counterparties.
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Debt Agreements
Summary of Outstanding Debt as of June 30, 2021
(1)
Highest Priority Lowest Priority
New RBL Second Lien Term Loan 6.75% (Unsecured)
Face amount $750 million $150 million $950 million
Amount outstanding $35 million $150 million $950 million
December 2024, or 91 days
prior to the maturity of the
Scheduled maturity date Second Lien Term Loan, to December 2025 April 2029
the extent any of such
indebtedness remains
outstanding
Interest rate LIBOR + 3.0 - 4.0% LIBOR + 8.75% 6.75%
Base interest rate options ABR and LIBOR (with a floor ABR and LIBOR (with a floor N/A
of 0.50%) + spread of 0.75%) + spread
- Maximum consolidated total
net leverage ratio of 3.25x -Maximum consolidated total
effective April 2021 net leverage ratio of 4.0x
decreasing to 3.5x effective
Financial maintenance covenants April 2021 N/A
- Maximum Current Ratio of - Minimum liquidity of
1.00x effective April 2021 $40 million tested quarterly
- Minimum hedging - Minimum hedging
requirements requirements
- Incurrence of debt - Incurrence of debt - Incurrence of debt
- Incurrence of liens - Incurrence of liens - Incurrence of liens
- Payment of dividends - Payment of dividends - Payment of dividends
- Equity purchases - Equity purchases - Equity purchases
- Asset sales - Asset sales - Asset sales
- Limitations on
- Limitations on derivatives - Limitations on derivatives ability to make
Significant restrictive covenants & investments & investments investments
- Affiliate
- Affiliate transactions - Affiliate transactions transactions
- Restricted payments
- Limitations on
- Excess cash cap Guarantees by
Restricted
Subsidiaries
Make-whole through
April 2024. After
Make-whole through June April 2024 through
Optional redemption Any time at par 2022; 102% through June April 2025 at
2023; 101% through June 103.375%; thereafter
2024; thereafter at par through April 2026 at
101.688%; thereafter
at par.
If accompanied by
Change of control Event of default Event of default Ratings Decline,
Investor put at 101%
of par
(1) This information is qualified in all respects by reference to the full text
of the covenants, provisions and related definitions contained in the
documents governing the various components of our debt.
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