ROSEHILL RESOURCES : Management's Discussion and Analysis of Financial Condition and Results of Operations. (form 10-Q)

The following discussion and analysis of our financial condition and results of
operations should be read in conjunction with the condensed consolidated
financial statements and notes thereto appearing elsewhere in this Quarterly
Report on Form 10-Q. The following discussion contains forward-looking
statements that reflect our future plans, estimates, beliefs and expected
performance. The forward-looking statements are dependent upon events, risks and
uncertainties that may be outside of our control. Our actual results could
differ materially from those discussed in these forward-looking statements.
Factors that could cause or contribute to such differences include, but are not
limited to, market prices for oil, natural gas and NGLs, production volumes,
estimates of proved reserves, capital expenditures, economic and competitive
conditions, regulatory changes and other uncertainties, as well as those factors
discussed below and in our Annual Report on Form 10-K, particularly in "Item 1A.
Risk Factors" and below in "Cautionary Statement Concerning Forward-Looking
Statements," 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 CONCERNING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes "forward-looking statements" within
the meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act") and Section 21E of the Exchange Act. All statements, other
than statements of historical fact included in this report, regarding our
strategy, future operations, financial position, estimated revenues and losses,
projected costs, prospects, plans and objectives of management are
forward-looking statements. When used in this Quarterly Report on Form 10-Q, the
words "could," "believe," "anticipate," "intend," "estimate," "expect,"
"project" and similar expressions are intended to identify forward-looking
statements, although not all forward-looking statements contain such identifying
words. These forward-looking statements are based on management's current
expectations and assumptions about future events and are based on currently
available information as to the outcome and timing of future events. When
considering forward-looking statements, you should keep in mind the risk factors
and other cautionary statements described under "Risk Factors" in our Annual
Report on Form 10-K for the year ended December 31, 2019 (our "Annual Report on
Form 10-K"), and the risk factors and other cautionary statements contained in
our other filings with the SEC. These forward-looking statements are based on
management's current beliefs as of the date of this Quarterly Report on Form
10-Q, based on currently available information, as to the outcome and timing of
future events.

Forward-looking statements may include statements about:

• the timing and results of the RSA, the Chapter 11 Filings, including our

ability to obtain confirmation of the Plan or an alternative restructuring

transaction;

• our ability to consummate the transactions contemplated by the RSA, including

the Plan and the DIP Credit Agreement, on the terms described or at all;

• our ability to obtain the approval of the Bankruptcy Court with respect to

motions or other requests made to the Bankruptcy Court in the Chapter 11

Filings, including maintaining strategic control as debtor-in-possession;

• the effects of the RSA and the Chapter 11 Filings on our operations and

financial condition and on the interests of the various constituents,

including holders of our common stock and indebtedness;

• the length of time that we will operate under Chapter 11 protection and the

continued availability of capital during the pendency of the proceedings;

• the adequacy and availability of capital resources, credit and liquidity,

including, but not limited to, debt refinancing or extensions, exchanges or

repurchases of debt, issuances of debt or equity securities, access to

additional borrowing capacity and our ability to generate sufficient cash

flow from operations to fund our capital expenditures and meeting working

capital needs;

• delisting our common stock and terminating our SEC reporting obligations;

• our future financial performance;

• our ability to continue as a going concern;

• the impact of the COVID-19 pandemic;

• our ability to successfully complete strategic initiatives, including

potential refinancings, restructuring or deleveraging;

• potential actions of our stakeholders and lenders, including before and after

the Chapter 11 Filings;

• our ability to cure defaults under our debt agreements;

• our business strategy;


• our reserves;

• our liquidity and capital resources;

• our ability to comply with covenants and obligations under our financing

agreements;

• the future of our operations;

• our drilling prospects, inventories, projects and programs;

• our ability to replace the reserves we produce through drilling and property

    acquisitions;



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• our ability to realize the anticipated benefits of the White Wolf Acquisition;

• our financial strategy, liquidity and capital required for our development

program;

• benefits from changes in our capital program and development strategy;

• our realized oil, natural gas and natural gas liquids ("NGL") prices;

• the timing and amount of our future production of oil, natural gas and NGLs;

• our hedging strategy and results;

• our future drilling plans;

• our expansion plans and future opportunities;

• our competition and government regulations;

• our ability to obtain permits and governmental approvals;

• our pending legal or environmental matters;

• our marketing of oil, natural gas and NGLs;

• our leasehold or business acquisitions;

• our costs of developing our properties;

• general economic conditions;

• credit markets;

• uncertainty regarding our future operating results; and

• our plans, objectives, expectations and intentions contained in this

Quarterly Report on Form 10-Q that are not historical.

You should not place undue reliance on these forward-looking statements. These
forward-looking statements are subject to a number of risks, uncertainties and
assumptions, including but not limited to actions taken by our stakeholders
(including those not party to the RSA), our creditors, our debt holders and our
customers and litigation and disputes (both before and after the Chapter 11
Filings), our ability to have sufficient liquidity to consummate the Plan
(particularly if the Plan is not consummated within our expected timeframe), our
ability to continue as a going concern and the impact of the COVID-19 pandemic
and the actions by governments, businesses and individuals in response to the
pandemic, as well as the risks described under "Risk Factors" in our Annual
Report on Form 10-K, many of which may be aggravated by the effects of the
COVID-19 pandemic. Moreover, we operate in a very competitive and rapidly
changing environment, particularly in light of the COVID-19 pandemic and the
recent significant decline in commodity prices. New risks emerge from time to
time. It is not possible for our management to predict all risks, nor can we
assess the impact of all factors on our business or the extent to which any
factor, or combination of factors, may cause actual results to differ materially
from those contained in any forward-looking statements we may make.

Reserve engineering is a process of estimating underground accumulations of oil
and natural gas that cannot be measured in an exact way. The accuracy of any
reserve estimate depends on the quality of available data, the interpretation of
such data and price and cost assumptions made by reserve engineers. In addition,
the results of drilling, testing and production activities may justify revisions
of estimates that were made previously. If significant, such revisions would
change the schedule of any further production and development drilling.
Accordingly, reserve estimates may differ significantly from the quantities of
oil and natural gas that are ultimately recovered.

Although we believe that our plans, intentions and expectations reflected in or
suggested by the forward-looking statements we make in this Quarterly Report on
Form 10-Q are reasonable, we can give no assurance that these plans, intentions
or expectations will be achieved or occur, and actual results could differ
materially and adversely from those anticipated or implied by the
forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly
Report on Form 10-Q are expressly qualified in their entirety by this cautionary
statement. This cautionary statement should also be considered in connection
with any subsequent written or oral forward-looking statements that we or
persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update
any forward-looking statements, all of which are expressly qualified by the
statements in this section, to reflect events or circumstances after the date of
this Quarterly Report on Form 10-Q.

Overview

We are an independent oil and natural gas company focused on the acquisition,
exploration, development and production of unconventional oil and associated
liquids-rich natural gas reserves in the Permian Basin. Our assets are
concentrated in the Delaware Basin, a sub-basin of the Permian Basin. We have
drilling locations in ten distinct formations in the Delaware Basin: the Brushy
Canyon, Upper Avalon, Lower Avalon, 2nd Bone Spring Shale, 2nd Bone Spring Sand,
3rd Bone Spring Sand, 3rd Bone Spring Shale, Wolfcamp A (X/Y), Lower Wolfcamp A
and Wolfcamp B, and our goal is to build a premier development and acquisition
company focused on horizontal drilling in the Delaware Basin.

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We have no direct operations and no significant assets other than our ownership
interest in Rosehill Operating, an entity of which we act as the sole managing
member and of whose common units we currently own approximately 64.7% (or 70.8%
assuming the conversion of Rosehill Operating Series A Preferred Units into
Rosehill Operating Common Units).

Restructuring Support Agreement and Related Recent Developments

Restructuring Support Agreement

On June 30, 2020, the Company Parties entered into the RSA, which includes the Term Sheet with the Consenting Creditors.

The RSA contemplates that the Company Parties will (i) file the Chapter 11 Filings with the Bankruptcy Court to effect the Plan, which will be filed with the Bankruptcy Court on or before July 15, 2020 at 11:59 p.m. (prevailing Central Time) and (ii) enter into the DIP Facility as evidenced by the DIP Credit Agreement (as defined in the RSA).

The RSA contains certain covenants on the part of each of the Company Parties
and the Consenting Creditors including that the Consenting Creditors use
commercially reasonable efforts to support the Restructuring Transactions (as
defined in the RSA), to vote in favor of the plan of reorganization contemplated
by the RSA (the "Plan") and to otherwise use good faith when negotiating the
forms of the Definitive Documents (as defined in the RSA) with the Company
Parties. The RSA also provides for certain conditions to the obligations of the
parties and for termination upon the occurrence of certain events, including
without limitation, the failure to achieve certain milestones and certain
breaches or other actions by the parties under the RSA.

Proposed Plan of Reorganization

The Plan as contemplated by the RSA will provide for the following, among other things:

• after the Effective Date, New Rosehill will be established;

• the entry by New Rosehill into an exit RBL credit agreement to refinance the

    Revolving Credit Facility, with a term of 4 years and a maximum initial
    borrowing base of $235.0 million;

• the principal of the DIP Facility will be converted to 24.15% of the New

Common Shares, and the backstop fee earned in connection with the DIP

Facility will be converted to 1.69% of the New Common Shares, in each case

subject to dilution from the MIP;

• each Consenting Noteholder will receive its pro rata share of 68.60% of the

New Common Shares, subject to dilution from the MIP, in exchange for all of

the Secured Note Claims (as defined in the Term Sheet);

• Tema, as the holder of claims under the Tax Receivable Agreement, will

receive its pro rata share of 4.08% of the New Common Shares, subject to

dilution from the MIP, in exchange for all of the TRA Claims (as defined in

    the Term Sheet);

• subject to specific conditions, including acceptance of the Plan and lack of

any objection to the confirmation of the Plan by the Preferred Holders, the

Preferred Holders will receive their pro rata share of 1.48% of the New

Common Shares, subject to dilution from the MIP, in exchange for all of the

Series A Preferred Stock and Series B Preferred Stock;

• the Existing Common Stock (which includes the Company's Class A Common Stock)

and Other Existing Interests (each as defined in the Term Sheet) will be

cancelled and receive no recovery;

• the RSA requires that Tema and the Consenting Noteholders work in good faith

to finalize substantially final forms of governance documents or term sheets

in respect thereof before the Petition Date;

• certain claims relating to borrowings outstanding under the Amended and

Restated Credit Agreement are to be paid with net cash proceeds from the

orderly unwind of all of the Company's existing commodity hedging and

derivative instruments, which is anticipated to occur between the execution

of the RSA and the Petition Date; and

• the Gas Gathering Agreement will be amended after the execution of the RSA

    and before the Petition Date.




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The terms of the Plan are subject to approval by, among other parties, the
Consenting Creditors (pursuant to the terms set forth in the RSA) and the
Company, as well as the Bankruptcy Court, among other conditions to the
effectiveness of the Plan. The Company Parties intend to solicit votes from the
Consenting Creditors with respect to the Plan prior to the Petition Date, and to
commence solicitation of votes from the Preferred Holders prior to the Petition
Date but to receive such votes after the Petition Date. Accordingly, no
assurance can be given that the transactions described herein will be
consummated. During the Chapter 11 proceedings, a termination of the RSA may
result in the loss of support for the Plan, which would adversely affect our
ability to confirm and consummate the Plan. If the Plan is not consummated,
there can be no assurance that we could achieve a restructuring alternative and
our Chapter 11 proceedings could become protracted or terminate, which would
have a material adverse effect on our liquidity and ability to continue as a
going concern.

The foregoing summary of the terms of the Plan does not purport to be complete
and is qualified in its entirety by the full text of the RSA (including the Term
Sheet), which is attached as an exhibit hereto and incorporated herein by
reference.

Debtor-in-Possession Financing

The RSA contemplates that the Company Parties will file the DIP Motion seeking,
among other things, interim and final approval of debtor-in-possession financing
on the terms and conditions set forth in the DIP Credit Agreement. If approved
by the Bankruptcy Court, the RSA provides that the DIP Credit Agreement will
provide for the following, among other things:

• the DIP Facility, in the aggregate amount of $17.5 million, shall be junior

to the Adequate Protection Liens (as defined in the Term Sheet),

superpriority liens securing postpetition hedges, the Revolving Credit

Facility and the Note Purchase Agreement but senior to all other Claims (as

defined in the Term Sheet) and Interests (as defined in the Term Sheet);

• $15.0 million of the DIP Facility will be backstopped by the Consenting

Noteholders, and $2.5 million shall be backstopped by Tema;

• Tema will have the right to subscribe to provide up to $7.5 million of the

    DIP Facility;

• the Company Parties will draw half of the DIP Facility within three business

days after the entry of the Interim Order, and the remaining half of the DIP

Facility within three business days after the entry of the Final Order;

• the DIP Facility will mature at the earliest of (i) six months after the

Petition Date, (ii) the Effective Date; (iii) the closing of a sale of

substantially all of the equity interests or assets of the Company Parties

(unless done pursuant to the Plan); (iv) the date of prepayment in cash in

full by the Company of all claims under the DIP Facility and termination of

all commitments in respect of the DIP Facility in accordance with the terms

of the DIP Credit Agreement; and (v) the date of termination of the

commitments in respect of the DIP Facility and/or acceleration of any

outstanding extensions of credit following the occurrence and during the

continuance of an event of default under the DIP Facility;

• borrowings under the DIP Facility will bear interest at 8% per annum,

paid-in-kind monthly, with an additional 2% per annum default rate

paid-in-kind, provided that such interest may only be paid in cash upon the

Effective Date subject to certain conditions;

• the Company Parties will pay an upfront fee of 100 bps, paid-in-kind,

provided that such upfront fee may only be paid in cash upon the Effective

Date subject to certain conditions;

• the DIP Credit Agreement will provide for certain customary covenants

applicable to the Company;

• the DIP Credit Agreement will require that the Company Parties (a) enter into

commodity hedge transactions pursuant to standards agreed in advance by the

Company, the Majority DIP Lenders (as defined in the Term Sheet), and

JPMorgan in their reasonable discretion such that, as soon as practical after

the Petition Date (and in any case no later than ten (10) Business Days after

the Petition Date), the notional volumes of such commodity hedge transactions

represent at least 70% of reasonably anticipated projected production from

oil and gas properties constituting proved developed producing reserves of

Rosehill Operating for each of the following 24 months (August 2020 to July

2022 based on the most recent reserve report) for each of crude oil and

natural gas, calculated separately, (b) receive prior written consent from

Majority DIP Lenders and JPMorgan (acting at the direction of the Required

Revolving Credit Agreement Lenders (as defined in the Term Sheet)) for any

asset sales or dispositions outside the ordinary course of business in excess

of $200,000 in the aggregate or investments in excess of $200,000 in the

aggregate, and (c) provide certain periodic reporting packages and budgets to

    the Majority DIP Lenders and JPMorgan; and




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• the DIP Credit Agreement will provide for certain customary conditions for

debtor-in-possession facilities of this type and certain other conditions as

required by the Majority DIP Lenders.

The terms of the DIP Credit Agreement are subject to approval by the DIP
Lenders, the Company, and the Bankruptcy Court , among other conditions.
Accordingly, the terms of the DIP Credit Agreement are subject to change and
there can be no assurance that the DIP Credit Agreement will be consummated. The
Company anticipates closing the DIP Credit Agreement promptly following approval
by the Bankruptcy Court of the DIP Motion. If a termination occurs prior to the
Chapter 11 Filings, then our lenders and noteholders could exercise remedies for
Events of Default (as defined in the respective agreements) (including
accelerating debt, sweeping cash and foreclosing on our assets).

The foregoing summary of the terms of the proposed DIP Facility does not purport to be complete and is qualified in its entirety by the full text of the RSA (including the Term Sheet) which is attached as an exhibit and incorporated herein by reference.

For information regarding certain events leading up to the execution of the RSA, please read Note 3 - Liquidity and Chronology of Events and Going Concern Assessment within this MD&A.

Risks Associated with Chapter 11 Filings

There can be no assurance that we will make the Chapter 11 Filings in accordance
with the RSA, that the RSA will not be terminated or that we will consummate the
Plan as contemplated. In any event, the preparation of the RSA and the Chapter
11 Filings have and will continue to result in material expenses for the Company
and the attention of management. For the duration of our Chapter 11 Cases, our
operations and our ability to develop and execute our business plan are subject
to the risks and uncertainties associated with the reorganization process under
the Bankruptcy Code as described in Part II, Item 1A. "Risk Factors" in this
quarterly report on Form 10-Q. Due to these risks and uncertainties, the
description of our operations, properties and capital plans included in this
quarterly report on Form 10-Q may not accurately reflect our operations,
properties and capital plans following the conclusion of the Chapter 11
proceedings.

Delisting of Class A Securities

In connection with the Chapter 11 Filings, as contemplated by the Term Sheet,
the Company intends to delist its Class A Common Stock, Class A Common Stock
Public Units and Class A Common Stock Public Warrants from Nasdaq June 30, 2020.
The Company also expects to suspend its reporting obligations under the Exchange
Act when it is eligible to do so.

Market Conditions

Irrespective of our balance sheet constraints, sustained periods of low prices
for oil or natural gas have and could materially and adversely affect our
financial position, our results of operations, the quantities of oil and natural
gas reserves that we can economically produce and our access to capital.

On January 30, 2020, the World Health Organization ("WHO") announced a global
health emergency because of a new strain of coronavirus originating in Wuhan,
China (the "COVID-19 outbreak") and the risks to the international community as
the virus spread globally beyond its point of origin. In March 2020, the WHO
classified the COVID-19 outbreak as a pandemic, based on the rapid increase in
exposure globally.

The adverse economic effects of the COVID-19 outbreak have materially decreased
demand for oil based on the restrictions implemented by governments trying to
slow the spread of the outbreak and changes in consumer behavior and this
decrease in demand has generated a surplus of oil supply that has created a
saturation of storage. The surplus in supply in turn has led to a significant
decrease in oil prices. In addition, in March 2020, members of OPEC+ failed to
agree on oil production levels and Saudi Arabia responded by increasing its
production, which resulted in an increased supply of oil and further contributed
to the substantial decline in oil prices and an increasingly volatile market.
The members of OPEC+ reached a tentative agreement to cut oil production in
April 2020; however, the announcement of the tentative agreement did not result
in increased commodity prices, and these production cuts, if effected, may not
offset near-term demand loss attributable to the COVID-19 pandemic and related
economic slowdown.

We have certain commodity derivative instruments in place to mitigate the
effects of such price declines as detailed in Note 8 - Derivative Instruments;
however, the derivatives will not entirely mitigate the effects of lower oil
prices. The depressed pricing environment has led us to halt our drilling and
completion activities for the remainder of 2020 and has led to (i) a reduction
in reserves, including the removal of proved undeveloped reserves, (ii) an
impairment of proved and unproved oil and gas properties, (iii) curtailment of
production during the second quarter of 2020, (iv) recognition of a full
valuation allowance on our net deferred

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tax assets and (v) a reduction of our Tax Receivable Agreement liability.
Production has continued to be adversely impacted during the second quarter of
fiscal 2020 and we expect this to continue into the third quarter of fiscal 2020
and possibly beyond.

The full impact of the COVID-19 outbreak continues to evolve as of the date of
this report and will depend on various factors, including the duration and
spread of the outbreak, its severity, the actions by governments, businesses and
individuals in response to the situation, how the pandemic and measures taken in
response to its impact demand for oil, the availability of personnel, equipment
and services critical to our ability to operate our properties, and how quickly
and to what extent normal economic and operating conditions can resume, each of
which is highly uncertain and cannot be predicted. Moreover, if workers at one
of our offices become ill or are quarantined and in either or both events are
therefore unable to work, our operations could be subject to disruption.
Further, if our vendors become unable to obtain necessary raw materials or
components, we may incur higher supply costs or our vendors may be required to
reduce service or production levels, either of which may negatively affect our
financial condition or results of operations. As such, it is uncertain as to the
full magnitude of the impact that the pandemic will have on our financial
condition, liquidity, and future results of operations. Management continues to
actively monitor the impact of the global situation on our financial condition,
liquidity, operations, suppliers, industry, and workforce.

Realized Prices

Our revenue, profitability and future growth are highly dependent on the prices
we receive for our oil and natural gas production, as well as NGLs that are
extracted from our natural gas during processing. The following table presents
our average realized commodity prices before the effects of commodity derivative
settlements:

                          Three Months
                         Ended March 31,
                         2020        2019
Crude oil (per Bbl)   $   44.84    $ 48.92
Natural gas (per Mcf) $    0.05    $  0.85
NGLs (per Bbl)        $    7.59    $ 15.26



The oil and natural gas industry is cyclical and commodity prices are highly
volatile. As discussed above, the impact of the COVID-19 outbreak and the
failure of OPEC+ to agree on oil production levels caused oil prices to decline
significantly in the second half of March 2020. The impact of the lower oil
prices led us to production curtailment and suspension of our drilling and
completion activity and was the primary driver for the Company recording an
impairment to proved property of $333.8 million as of March 31, 2020. If oil
prices remain depressed for the remainder of 2020, it may further materially and
adversely affect our business, financial condition, results of operations,
operating cash flows, liquidity or ability to finance planned capital
expenditures. Lower oil, natural gas and NGL prices may also reduce the
borrowing base under our Amended and Restated Credit Agreement, which may be
redetermined at the discretion of the lenders and is based on the collateral
value of our proved reserves that have been mortgaged to the lenders. We entered
into a forbearance agreement with the lenders under our Amended and Restated
Credit Agreement on May 4, 2020, which postponed the scheduled redetermination
of the borrowing base that was scheduled to occur on or about April 1, 2020. We
expected such borrowing base redetermination to result in a borrowing base
deficiency. Alternatively, higher oil, natural gas and NGL prices may result in
significant losses being incurred on our commodity derivatives, which could
cause us to experience net losses when oil and natural gas prices rise. We
received low prices for our natural gas due to lower NYMEX gas prices and wider
gas price differentials but because we receive revenue from NGLs, we have and
may continue to produce and sell our natural gas at a low, or negative, realized
sales price.

A 10% change in our realized oil, natural gas and NGL prices would have changed revenue by the following amounts for the periods indicated:

                      Three Months
                     Ended March 31,
                     2020        2019
                     (In thousands)
Oil sales         $   5,775    $ 6,585
Natural gas sales        10        147
NGL sales               234        453
Total revenues    $   6,019    $ 7,185



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The prices we receive for our products are based on benchmark prices and are
adjusted for quality, energy content, transportation fees and regional price
differentials. See "Results of Operations" below for an analysis of the impact
changes in realized prices had on our revenues.

Sources of Our Revenues

Our revenues are derived from the sale of our oil and natural gas production, as
well as the sale of NGLs that are extracted from our natural gas during
processing. The following table shows the percentage each component contributed
to total revenue:
                           Three Months
                          Ended March 31,
Commodity Revenues (1):   2020        2019
Oil sales                  96 %        92 %
Natural gas sales           -           2
NGL sales                   4           6
                          100 %       100 %

(1) The percentages exclude the effects of commodity derivatives.

Operational and Financial Highlights for the Three Months Ended March 31, 2020 and 2019

Production Results

The following table presents production volumes for our properties for the
periods indicated:
                                         Three Months
                                       Ended March 31,
                                        2020       2019
Oil (MBbls)                            1,288       1,346
Natural gas (MMcf)                     1,921       1,739
NGLs (MBbls)                             308         297
Total (MBoe)                           1,916       1,933

Average daily net production (Boe/d) 21,055 21,478

Derivative Activity

To achieve a more predictable cash flow and reduce exposure to adverse
fluctuations in commodity prices, we have historically used commodity derivative
instruments, such as swaps, two-way costless collars and three-way costless
collars, to hedge price risk associated with a portion of our anticipated oil,
natural gas and NGL production. By removing a significant portion of the price
volatility associated with our production, we will mitigate, but not eliminate,
the potential negative effects of declines in benchmark oil, natural gas and NGL
prices on our cash flow from operations for those periods. However, for a
portion of our current positions, hedging activity may also reduce our ability
to benefit from increases in oil, natural gas and NGL prices. We will sustain
losses to the extent our commodity derivative contract prices are lower than
market prices and, conversely, we will sustain gains to the extent our commodity
derivative contract prices are higher than market prices. In certain
circumstances, where we have unrealized gains in our commodity derivatives
portfolio, we may choose to restructure existing commodity derivative contracts
or enter into new transactions to modify the terms of current contracts in order
to realize the current value of our existing positions.


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We had a net current asset of $79.9 million and a net non-current asset of $60.8
million related to the following open commodity derivative instrument positions
as of March 31, 2020:
                                                       2020            2021            2022
Commodity derivative swaps
Oil:
   Notional volume (Bbls) (1)(2)                       760,000               -               -
   Weighted average fixed price ($/Bbl)           $      67.46     $         -     $         -
Natural gas:
   Notional volume (MMBtu)                           1,595,368       

1,615,792 1,276,142

Weighted average fixed price ($/MMbtu) $ 2.73 $ 2.79 $ 2.85

Commodity derivative three-way collars
Oil:
   Notional volume (Bbls)                            2,475,000       

4,200,000 2,000,000

Weighted average ceiling price ($/Bbl) $ 70.29 $ 60.40 $ 61.45

   Weighted average floor price ($/Bbl)           $      57.50     $     

54.49 $ 55.00

   Weighted average sold put option price ($/Bbl) $      47.50     $     45.51     $     45.00

Crude oil basis swaps
Midland / Cushing:
   Notional volume (Bbls)                            3,905,000       4,200,000       2,100,000
   Weighted average fixed price ($/Bbl)           $      (0.85 )   $      0.49     $      0.54

Argus WTI roll:
   Notional volume (Bbls)                              370,650               -               -
   Weighted average fixed price ($/Bbl)           $       0.40     $         -     $         -

NYMEX WTI roll:
   Notional volume (Bbls)                            2,102,752               -               -
   Weighted average fixed price ($/Bbl)           $       0.42     $         -     $         -

Natural gas basis swaps
EP Permian:
   Notional volume (MMBtu)                           1,617,388               -               -

Weighted average fixed price ($/MMBtu) $ (1.03 ) $

- $ -

(1) During the second quarter of 2019, the Company entered into commodity

derivative swaps where it bought 2,160,000 barrels of crude oil at a weighted

average fixed price of $50.48 per barrel to offset commodity derivative swaps

for the year ended December 31, 2021, it previously sold of 2,160,000 barrels

of crude oil at a weighted average fixed price of $61.21 per barrel,

effectively locking in a gain of approximately $23.2 million that the Company

expects to recognize in 2021 when the swaps settle.

(2) During the second quarter of 2019, the Company entered into commodity

derivative swaps where it bought 1,100,000 barrels of crude oil at a weighted

average fixed price of $50.55 per barrel to offset commodity derivative swaps

for the year ended December 31, 2022, it previously sold of 1,100,000 barrels

of crude oil at a weighted average fixed price of $58.42 per barrel,

effectively locking in a gain of approximately $8.7 million that the Company

    expects to recognize in 2022 when the swaps settle.



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If there were no changes in the forward curve market prices as of March 31,
2020, we would recognize a realized gain of $63.9 million in 2020, a realized
gain of $54.8 million in 2021 and a realized gain of $22.0 million in 2022
related to our commodity derivatives. Our commodity derivative portfolio had a
mark-to-market net asset value of approximately $125.8 million as of April 30,
2020. See Note 8 - Derivative Instruments in the condensed consolidated
financial statements under Part I, Item 1 of this Quarterly Report on Form 10-Q
for additional information about our derivatives.

We utilize interest rate swaps to reduce our exposure to adverse fluctuations in
LIBO rates on a portion of our revolving credit facility outstanding borrowings.
The gains and losses on our interest rate swaps are recognized in interest
expense. Entering into interest rate swaps allows us to mitigate, but not
eliminate, the negative effects of increases in the LIBO rate, but reduces our
ability to benefit from any decreases in the LIBO rate. We have interest rate
swaps that extend through August 2022 on a notional amount of $150.0 million of
our outstanding borrowings under our revolving credit facility at an average
fixed rate of 1.721%. We had a net current liability of $2.1 million and a net
non-current liability of $3.0 million related to our interest rate swaps as of
March 31, 2020.

Income Taxes

Rosehill Operating is a limited liability company that is treated as a
partnership for U.S. federal income tax purposes and is not subject to U.S.
federal income tax. Rosehill Resources is a C corporation and is subject to U.S.
federal, state and local income taxes. Any taxable income or loss generated by
Rosehill Operating is passed through to and included in Rosehill Resources and
the noncontrolling interest taxable income or loss. On a consolidated basis, our
effective tax rate will differ from the enacted statutory rate of 21% and will
fluctuate from period to period primarily due to the allocation of profits and
losses to Rosehill Resources and the noncontrolling interest holder in
accordance with the LLC Agreement and the impact of state income taxes.

We periodically assesses whether it is more likely than not that we will
generate sufficient taxable income to realize our deferred tax assets, including
NOL carry forwards or carry backs. A valuation allowance for deferred tax assets
is recognized when it is more likely than not that some or all of the benefit
from the deferred tax assets will not be realized. As of March 31, 2020, we had
a full valuation allowance to offset our net deferred tax assets in excess of
deferred tax liabilities because we believe it is more likely than not that our
deferred tax will not be realized prior to their expiration due to uncertainty
of the market, the significant decline in oil prices that began during the first
quarter of 2020 and the Company having substantial doubt about its ability to
continue as a going concern.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

• production volumes;

• Adjusted EBITDAX as defined under "Non-GAAP Financial Measure"; and

• operating expenses on a per barrel of oil equivalent ("Boe"), as discussed in

    "Results of Operations."




                                       45

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Non-GAAP Financial Measure

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by
our management and external users of our financial statements, such as industry
analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as
net income (loss) before interest expense, net, income tax expense (benefit),
DD&A, accretion, impairment of oil and natural gas properties, exploration
costs, stock-settled stock-based compensation, (gains) losses on commodity
derivatives excluding net cash receipts (payments) on settled commodity
derivatives, (gains) losses from the disposition of property and equipment,
(gains) losses on asset retirement obligation settlements and other non-cash
operating items. Adjusted EBITDAX is not a measure of net income (loss) as
determined by U.S. GAAP.

Management believes Adjusted EBITDAX is useful because it allows them to more
effectively evaluate operating performance and compare our results of operations
from period to period against our peers without regard to financing methods or
capital structure. We exclude the items listed above from net income (loss) in
arriving at Adjusted EBITDAX because these amounts can vary substantially 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 as an alternative to,
or more meaningful than, net income (loss) as determined in accordance with U.S.
GAAP or as an indicator of our operating performance or liquidity. 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 structure 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 its results will be unaffected by
unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be
comparable to other similarly titled measures of other companies.

We have provided below a reconciliation of Adjusted EBITDAX to net income (loss), the most directly comparable U.S. GAAP financial measure.

                                                            Three Months
                                                           Ended March 31,
                                                         2020           2019
                                                           (In thousands)
Net loss                                             $ (230,328 )   $ (104,072 )
Interest expense, net                                    10,814          5,600
Income tax expense (benefit)                             37,027          3,306

Depreciation, depletion, amortization and accretion 31,486 35,964 Impairment of oil and natural gas properties

            333,840             

-

Unrealized (gain) loss on commodity derivatives, net (101,613 ) 103,548 Stock settled stock-based compensation

                      118            

974

Exploration costs                                        13,720          

1,255

(Gain) loss on disposition of property and equipment         18             

9

Other non-cash (income) expense, net (1)                (54,060 )          (81 )
Adjusted EBITDAX                                     $   41,022     $   46,503

(1) Includes a $53.6 million non-cash adjustment to our Tax Receivable Agreement

    liability.







                                       46

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Results of Operations

Three Months Ended March 31, 2020 Compared to Three Months Ended March 31, 2019

Oil, Natural Gas and NGL Sales Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period's respective average sales prices and volumes:

                                          Three Months Ended March 31,
                                               2020             2019         Change        Change %
                                           (Dollars in thousands, except price data)
Revenues:
Oil sales                                $        57,752     $  65,853     $  (8,101 )        (12 )%
Natural gas sales                                    104         1,474        (1,370 )        (93 )
NGL sales                                          2,338         4,533        (2,195 )        (48 )
Total revenues                           $        60,194     $  71,860     $ (11,666 )        (16 )%

Average sales price (1):
Oil (per Bbl)                            $         44.84     $   48.92     $   (4.08 )         (8 )%
Natural gas (per Mcf)                               0.05          0.85         (0.80 )        (94 )
NGLs (per Bbl)                                      7.59         15.26         (7.67 )        (50 )
Total (per Boe)                          $         31.42     $   37.18     $   (5.76 )        (15 )%
Total, including effects of gain (loss)
on settled
 commodity derivatives, net (per Boe)    $         35.86     $   36.65     $   (0.79 )         (2 )%

Net production:
Oil (MBbls)                                        1,288         1,346           (58 )         (4 )%
Natural gas (MMcf)                                 1,921         1,739           182           10
NGLs (MBbls)                                         308           297            11            4
Total (MBoe)                                       1,916         1,933           (17 )         (1 )%

Average daily net production volume:
Oil (Bbls/d)                                      14,154        14,956          (802 )         (5 )%
Natural gas (Mcf/d)                               21,110        19,322         1,788            9
NGLs (Bbls/d)                                      3,385         3,300            85            3
Total (Boe/d)                                     21,055        21,478          (423 )         (2 )%

(1) Excluding the effects of settled and unsettled commodity derivative

transactions unless noted otherwise.

The decrease in total revenues was due to a decrease in average sales price and
sales volume. The decrease in average sales price contributed to approximately
$9.2 million of the decrease in total revenues and the decrease in sales volume
contributed to approximately $2.5 million of the decrease to total revenues. The
decrease in average sales price is primarily driven by lower benchmark commodity
prices for oil, gas, and NGL. Our production remained relatively consistent
period over period as we were able to bring on new production to offset declines
in more mature wells. We have halted all drilling and completion activities so
we expect to see production decline throughout 2020.


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Operating expenses. The following table summarizes our operating expenses for
the periods indicated:
                                          Three Months Ended March
                                                    31,
                                             2020          2019         Change       Change %
                                           (In thousands, except per Boe data)
Operating expenses:
Lease operating expenses                 $   12,095     $   9,635     $   2,460           26  %

Production taxes and ad valorem taxes 3,759 4,238 (479 ) (11 ) Gathering and transportation

                  1,371         2,361          (990 )        (42 )
Depreciation, depletion, amortization
and accretion                                31,486        35,964        (4,478 )        (12 )
Impairment of oil and natural gas
properties                                  333,840             -       333,840          100
Exploration costs                            13,720         1,255        12,465          993
General and administrative, excluding
stock-based compensation                     10,602         8,044         2,558           32
Stock-based compensation                         18         1,011          (993 )        (98 )
Loss on disposition of property and
equipment                                        18             9             9          100
Total operating expenses                 $  406,909     $  62,517     $ 344,392          551  %
Operating expenses per Boe:
Lease operating expenses                 $     6.31     $    4.98     $    1.33           27  %

Production taxes and ad valorem taxes 1.96 2.19 (0.23 ) (11 ) Gathering and transportation

                   0.72          1.22         (0.50 )        (41 )
Depreciation, depletion, amortization
and accretion                                 16.43         18.61         (2.18 )        (12 )
Impairment of oil and natural gas
properties                                   174.24             -        174.24          100
Exploration costs                              7.16          0.65          6.51        1,002
General and administrative, excluding
stock-based compensation                       5.53          4.16          1.37           33
Stock-based compensation                       0.01          0.52         (0.51 )        (98 )
Loss on disposition of property and
equipment                                      0.01             -          

0.01 100 Total operating expenses per Boe $ 212.37 $ 32.33 $ 180.04 557 %

Lease operating expenses ("LOE"). LOE for the three months ended March 31, 2020
increased compared to the three months ended March 31, 2019. The increase in LOE
per Boe rate contributed to approximately $2.5 million of the increase in LOE
partially offset by a decrease of less than $0.1 million related to a decrease
in sales volume. Our LOE per Boe rate increased due to higher workovers, repair
and maintenance activity, and equipment rentals utilized for gas lift for the
three months ended March 31, 2020 compared to the three months ended March 31,
2019.

Production and ad valorem taxes. Production taxes for the three months ended
March 31, 2020 decreased by $0.7 million, or 21%, compared to the three months
ended March 31, 2019. Production taxes are primarily based on the market value
of our wellhead production. The decrease was primarily due to a decrease in
total revenues. Our total revenues decreased by 16% and production taxes
decreased by 21%. Production taxes as a percentage of total revenues were 4.6%
and 4.9% for the three months ended March 31, 2020 and 2019, respectively. Ad
valorem taxes for the three months ended March 31, 2020 increased by $0.2
million compared to the three months ended March 31, 2019 due to an increase in
producing wells.

Gathering and transportation ("G&T"). G&T for the three months ended March 31,
2020 decreased compared to the three months ended March 31, 2019. Approximately
$0.7 million of the decrease in G&T is primarily related to oil transportation
costs in Loving County. During the three months ended March 31, 2020, control of
our oil production in Loving County transferred to the customer at the lease and
oil transportation costs were netted against revenue in accordance with ASC 606.
During the three months ended March 31, 2019, control of our oil production in
Loving County transferred to the customer at a delivery point downstream from
the lease and the transportation costs to transport the oil production from the
lease to the delivery point were recorded to G&T. The remaining decrease to G&T
primarily relates to a lower realized G&T per Boe rate.


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Depreciation, depletion, amortization and accretion expense ("DD&A"). See the following table for a breakdown of DD&A:

                                              Three Months Ended March
                                                        31,
                                                 2020          2019        Change       Change %
                                               (In thousands, except per Boe data)
Components of DD&A and Accretion
Depreciation, depletion and amortization of
oil and gas properties                        $  30,933     $ 35,567     $ (4,634 )        (13 )%
Depreciation of other property and equipment        336          207          129           62
Accretion expense                                   217          190           27           14
                                              $  31,486     $ 35,964     $ (4,478 )        (12 )%

DD&A and Accretion per Boe
Depreciation, depletion and amortization of
oil and gas properties                        $   16.14     $  18.40     $  (2.26 )        (12 )%
Depreciation of other property and equipment       0.18         0.11         0.07           64
Accretion expense                                  0.11         0.10         0.01           10
Total DD&A and Accretion per Boe              $   16.43     $  18.61     $  

(2.18 ) (12 )%

The decrease in DD&A for our oil and gas properties was due to a decrease in
DD&A per Boe ("DD&A Rate") and sales volume. The decrease in the DD&A Rate
contributed to approximately $4.3 million of the decrease in DD&A for our oil
and natural gas properties and the decrease in sales volume contributed to
approximately $0.3 million of the decrease to DD&A for our oil and gas
properties. The DD&A Rate was lower for the three months ended March 31, 2020
compared to the three months ended March 31, 2019 primarily due to adding only
drilling and completion costs related to the proved reserves added at March 31,
2020, whereas during the three months ended March 31, 2019 a higher level of
infrastructure costs were being added to the depletion group without associated
proved reserves being added.

Impairment of oil and natural gas properties. Impairment of oil and natural gas
properties for the three months ended March 31, 2020 increased compared to the
three months ended March 31, 2019. As a result of the decrease in commodity
price forecasts at the end of the first quarter of 2020, specifically decreases
in oil and NGL prices, and the removal of proved undeveloped reserves due us
having substantial doubt about our ability to continue as a going concern, we
recorded impairment expense of $333.8 million to its proved oil and gas
properties for the three months ended March 31, 2020. We did not have any
impairments to proved property during the three months ended March 31, 2019.

Exploration costs. Exploration costs for the three months ended March 31, 2020
increased compared to the three months ended March 31, 2019. During March 2020,
we announced that we halted our drilling and completion activity and as a result
we expect to lose a portion of our undeveloped acreage through lease
expirations, which led to us recording an impairment to unproved property of
approximately $12.8 million. We did not have any impairments to unproved
property during the three months ended March 31, 2019.

General and administrative, excluding stock-based compensation ("G&A"). G&A for
the three months ended March 31, 2020 increased compared to the three months
ended March 31, 2019. As a result of the reduction of 52 full-time employees as
announced on March 26, 2020, we recorded an accrual for severance payments of
approximately $3.3 million. This increase was partially offset by a decrease in
our short-term incentive bonus accrual of approximately $1.3 million. We
implemented a new bonus incentive program in April 2020 and therefore no expense
was record during the first quarter of 2020.

Stock-based compensation. Stock-based compensation for the three months ended
March 31, 2020 decreased compared to the three months ended March 31, 2019
primarily due to forfeitures. Because we account for forfeitures as they occur
by reversing compensation cost previously recognized and associated with
unvested awards when the award is forfeited, we expect volatility in our
stock-based compensation. Stock-based compensation expense decreased
significantly during the three months ended March 31, 2020 due to forfeitures
related to the reduction of 52 full-time employees announced on March 26, 2020
and other employee departures in the quarter.


                                       49
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Other income and expenses. The following table summarizes our other income and expense for the periods indicated:

                                             Three Months Ended March 31,
                                               2020                2019            Change       Change %
                                                    (In thousands)
Other income (expense):
Interest expense, net                    $     (10,814 )     $        (5,600 )   $  (5,214 )         93  %
Gain (loss) on commodity derivative
instruments, net                               110,120              (104,571 )     214,691         (205 )
Other income, net                               54,108                    

62 54,046 87,171 Total other income (expense), net $ 153,414 $ (110,109 ) $ 263,523 (239 )%

Interest expense, net. Interest expense, net for the three months ended
March 31, 2020 increased compared to the three months ended March 31, 2019. In
July 2019, we entered into interest rate swaps that extend through August 2022
on a portion of our outstanding borrowing under our revolving credit facility.
The increase in interest expense for the three months ended March 31, 2020
primarily relates to an unrealized mark-to-market loss of approximately $4.5
million on our interest rate swaps. In addition, the interest expense related to
our revolving credit facility increased by $0.5 million during the three months
ended March 31, 2020 compared to the same period in 2019 as a result of an
increase in borrowings outstanding.

Gain (loss) on commodity derivative instruments, net. Net gains and losses on
our commodity derivatives are a function of fluctuations in the underlying
commodity prices versus fixed hedge prices, time decay associated with options
and the monthly settlement of the instruments. The total net gain for the three
months ended March 31, 2020 is comprised of net gains of $8.5 million on cash
settlements and net gains of $101.6 million on mark-to-market adjustments on
unsettled positions. The total net loss for the three months ended March 31,
2019 is comprised of net losses of $1.0 million on cash settlements and net
losses of $103.5 million on mark-to-market adjustments on unsettled positions.

Other income, net. Other income, net for the three months ended March 31, 2020
increased compared to the three months ended March 31, 2019. The increase is
primarily related to our revaluation of the Tax Receivable Agreement liability,
which resulted in an adjustment of $53.6 million. We account for amounts payable
under the Tax Receivable Agreement in accordance with ASC Topic 450,
Contingencies. Due to the uncertainty of the market, the significant decrease in
oil prices that began during the first quarter of 2020 and having substantial
doubt about our ability to continue as a going concern, it is not probable that
we will have sufficient future taxable income to utilize all the tax benefits
generated from the Tax Receivable Agreement.


                                       50
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Capital Requirements and Sources of Liquidity

Outlook

Considering the expected Chapter 11 Filings and the current environment for the
oil and natural gas industry, our goals in 2020 are to (1) expeditiously emerge
from the Chapter 11 Filings and (2) minimize production declines and operating
costs through efficient operations.

Chronology of Events and Going Concern Assessment

On January 30, 2020, the WHO announced a global health emergency because the
COVID-19 outbreak and the risks to the international community as the virus
spreads globally beyond its point of origin. In March 2020, the WHO classified
the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure
globally.

In addition, in March 2020, members of OPEC failed to agree on oil production
levels, which is expected to result in an increased supply of oil and has led to
a substantial decline in oil prices and an increasingly volatile market. The
Company has certain commodity derivative instruments in place to mitigate the
effects of such price declines as detailed in Note 8 - Derivative Instruments;
however, the derivatives will not entirely mitigate lower oil prices. The
depressed pricing environment led the Company to halt its drilling and
completion activities.

On March 19, 2020, we announced that we had fully drawn the available capacity
under our revolving credit facility, pursuant to the Amended and Restated Credit
Agreement. The draw was a precautionary measure in order to increase our cash
position and preserve financial flexibility in light of uncertainty in the
global markets and commodity prices. The draw brought our total outstanding
principal under the Amended and Restated Credit Agreement to $340 million as of
March 31, 2020.

On March 23, 2020, we received a letter from Nasdaq indicating that for the 30
consecutive business days ending March 20, 2020, the bid price of our Class A
Common Stock had closed below the $1.00 per share minimum bid price requirement
for continued listing on The Nasdaq Capital Market under Nasdaq Listing Rule
5550(a)(2). Under Nasdaq Listing Rule 5810(c)(3)(A), we have 180 calendar days
to regain compliance by meeting the continued listing standard, which was
extended by Nasdaq in light of market conditions resulting from the COVID-19
pandemic to December 3, 2020.

In March 2020, in response to the substantial decrease in crude oil prices
resulting from COVID-19 and the adverse effects on our financial condition as a
result thereof, we halted all drilling and completion activity, which has
resulted in a reduction in anticipated production and cash flows. Our future
cash flows from operations are subject to a number of variables, including
uncertainty in forecasted commodity pricing and production, redetermined
borrowing base capacity after the forbearance expires, which may be
significantly reduced, and our ability to reduce costs. We may generate
additional funds through (i) monetization of our commodity derivatives, subject
to any required approval from lenders (ii) the sale of non-core assets and (iii)
other sources of capital. We may not accomplish any of these alternatives on
acceptable terms or at all.

On April 1, 2020, we received a default notice from the agent under the Note Purchase Agreement, advising that the Identified Default had occurred.

On April 2, 2020, we received a default notice from JPMorgan Chase Bank, N.A.,
as agent under the Amended and Restated Credit Agreement, advising us that
Rosehill Operating had failed to deliver or file certain of its or our audited
financial statements without a "going concern" or like qualification or
exception by March 30, 2020, as required pursuant to Section 8.01(a) of the
Amended and Restated Credit Agreement, as well as the accompanying certificates
and reports contemplated by Sections 8.01(c), (d), (e) and (m) of the Amended
and Restated Credit Agreement. The default notice served as notice that the
lenders deemed such failure to be a Default (as defined in the Amended and
Restated Credit Agreement) under Section 10.01(e) of the Amended and Restated
Credit Agreement.

On April 15, 2020, we did not declare or pay the Series B Preferred Stock
Dividend that was due on that day. In order to make a dividend payment, our
Amended and Restated Credit Agreement requires that our borrowings outstanding
be 20% less than the committed borrowing capacity in place at the time of a
dividend payment. We were prohibited from declaring the Series B Preferred Stock
Dividend due to insufficient borrowing capacity under the Amended and Restated
Credit Agreement. As a result, the dividend rate of the Series B Preferred Stock
Dividend increased to 12% per annum until such a time as dividends are fully
paid and current, at which time the dividend rate will revert back to 10% per
annum. If we fail to pay the Series B Preferred Stock Dividend for nine
consecutive months, the holders of the Series B Preferred Stock may elect to
seek redemption of all or a portion of the Series B Preferred Stock, which
redemption amount was approximately $195.2 million had the full redemption
occurred as of March 31, 2020. We do not expect to be able to pay dividends on
the Series B Preferred Stock within the nine

                                       51
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consecutive months following April 15, 2020; as such, we expect the Series B
Preferred Stock would be redeemable at the holders' option after that time. If
the full redemption had occurred as of March 31, 2020, the redemption amount
would have been approximately $195.2 million.

On April 29, 2020, we received a default notice from the agent under the Note
Purchase Agreement, advising that, in addition to the Identified Default, the
Identified Event of Default had occurred.

On April 29, 2020, the New Rosehill Entities were dissolved pursuant to their organizational documents and the Delaware Limited Liability Company Act.

On May 4, 2020, we entered into the Forbearance Agreement with the lenders under
the Amended and Restated Credit Agreement. As a condition to the forbearance,
Rosehill Operating made a $20 million payment on the amounts outstanding under
the Amended and Restated Credit Agreement. Under the Forbearance Agreement, the
periodic redetermination of the borrowing base that was scheduled to occur on or
about April 1, 2020, which we expected to result in a borrowing base deficiency,
was postponed throughout the forbearance period, and the lenders agreed not to
accelerate the amounts owed under the Amended and Restated Credit Agreement as a
result of certain existing and anticipated Events of Default during the
forbearance period. During the forbearance period, the lenders have no
obligation to make any further loans under the Amended and Restated Credit
Agreement. In addition, the Forbearance Agreement requires us to comply with
certain other provisions, including that within 25 days of entering into the
Forbearance Agreement, we and certain stakeholders agree in principle to the
Restructuring Term Sheet and within 40 days of entering into the Forbearance
Agreement, we and those certain stakeholders enter into an RSA, which shall
provide for a restructuring under Chapter 11 of the U.S. Bankruptcy Code. The
Forbearance Agreement will terminate on July 3, 2020 unless terminated earlier
under these provisions. The dates by which the Company and certain stakeholders
were required to agree in principle to the Restructuring Term Sheet and enter
into the RSA were subsequently extended pursuant to certain letter agreements
between us, Rosehill Operating and the lenders under the Amended and Restated
Credit Agreement. As a condition to such letter agreements, we and Rosehill
Operating agreed that all settlement payments and other net cash proceeds
received in respect of any swap agreement be applied to the prepayment of the
Borrowings then outstanding under the Amended and Restated Credit Agreement.

On May 8 and 19, 2020, we received separate notices from the agent under the
Note Purchase Agreement, advising us of the Identified Events of Default and
that the holders reserved all of their rights, powers, privileges and remedies
under the Note Purchase Agreement, and asserted a right to an additional 2%
interest on the amounts outstanding under the Note Purchase Agreement.

We did not provide the lenders under the Amended and Restated Credit Agreement
and the Note Purchase Agreement with unaudited financial statements and other
required certificates and operating reports within 45 days after March 31, 2020,
which constituted a default under the Amended and Restated Credit Agreement and
the Note Purchase Agreement. The Amended and Restated Credit Agreement and the
Note Purchase Agreement each give us a 30-day cure period before it becomes an
event of default under the respective agreement. However, we were unable to
satisfy these requirements within the cure period. As such, this represents an
event of default under the Amended and Restated Credit Agreement and Note
Purchase Agreement.

Due to the matters noted above, debt outstanding under the Amended and Restated
Credit Agreement and the Second Lien Notes have been reflected as current in the
accompanying condensed consolidated balance sheet as of March 31, 2020.

On June 30, 2020, we entered into the RSA with the stakeholders named therein, pursuant to which we expect to file for protection under Chapter 11 of the Bankruptcy Code to effect consummation of the Plan. Please read Note 20 - Subsequent Events for more details.

These matters raise substantial doubt about our ability to continue as a going
concern for a period of one year after the date that these condensed
consolidated financial statements are issued. The condensed consolidated
financial statements included in this report have been prepared on a going
concern basis of accounting, which contemplates continuity of operations,
realization of assets and satisfaction of liabilities and commitments in the
normal course of business. The condensed consolidated financial statements do
not include adjustments that might result from the outcome of these
uncertainties.

Sources of Capital

Our activities require us to make significant operating, investing and financing
expenditures. Historically, our primary sources of liquidity have been cash
flows from operations, borrowings under our revolving credit agreement,
financing entered into in connection with acquisitions (such as the issuance of
the Series B Preferred Stock and Second Lien Notes), proceeds from the sale of
assets, and proceeds from issuance of equity securities. Many of these sources
are not currently available to us. As of

                                       52
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March 31, 2020, we had no availability under our revolving credit agreement. If
we are unable to obtain funds when needed or on acceptable terms, we may not be
able to finance the capital expenditures necessary to operate our producing
properties, recommence or execute on our drilling and completion program or
complete acquisitions that may be favorable to us.

In March 2020, we announced that we halted all drilling and completion activity.
We review our capital expenditure forecast periodically to assess changes in
current and projected cash flows, liquidity, debt requirements and other
factors. The suspension of our drilling and completion activity has resulted and
will continue to result in a reduction in anticipated production and cash flows.
Moreover, the recent significant decline in oil prices has further adversely
impacted cash flows and this is expected to continue until commodity prices
recover, the timing and extent of which is uncertain. Because we have curtailed
our drilling and completion program, we expect to lose a portion of our acreage
through lease expirations, which led to us recording an impairment to unproved
property of approximately $12.8 million.

Because we are the operator of a high percentage of our acreage, the timing and
level of our capital spending is largely discretionary and within our control.
As evidenced by the suspension of our drilling and completion program commencing
in late March 2020, we could choose to defer a portion of these planned capital
expenditures depending on a variety of factors, including, but not limited to,
the success of our drilling activities, prevailing and anticipated prices for
oil, natural gas and NGLs, the availability of necessary equipment,
infrastructure and capital, the receipt and timing of required regulatory
permits and approvals, seasonal conditions, drilling and acquisition costs and
the level of participation by other working interest owners. A deferral of
planned capital expenditures, particularly with respect to drilling and
completing new wells, will result in a reduction in anticipated production and
cash flows.

Following the Chapter 11 Filings, we and Rosehill Operating (together, the
"Debtors") expect to operate the business as "debtors-in-possession" under the
jurisdiction of the Bankruptcy Court and in accordance with the applicable
provisions of the Bankruptcy Code. Subject to certain exceptions under the
Bankruptcy Code, the Chapter 11 Filings will automatically enjoin or stay the
continuation of any judicial or administrative proceedings or other actions
against the Debtors or their property to recover, collect or secure a claim
arising prior to the filing of the Bankruptcy Petitions. Under the Plan, we
intend to ask the Bankruptcy Court to grant certain relief requested by the
Debtors enabling the Company to conduct its business activities in the ordinary
course, including, among other things and subject to the terms and conditions of
such orders, authorization to pay employee wages and benefits, to pay certain
taxes and governmental fees and charges, to continue to operate our cash
management system in the ordinary course, to secure debtor-in-possession
financing, to remit funds we hold from time to time for the benefit of third
parties (such as royalty owners), and to pay the prepetition claims of certain
of our vendors that hold liens under applicable non-bankruptcy law. In
connection with the Chapter 11 proceedings, under the terms of the RSA, we
expect to enter into the DIP Credit Agreement, if approved by the Bankruptcy
Court.

Despite the liquidity that may be provided by the DIP Credit Agreement, our
ability to maintain normal credit terms with our suppliers and vendors may
become impaired. We may be required to pay cash in advance to certain vendors
and may experience restrictions on the availability of trade credit, which would
further reduce our liquidity. If liquidity problems persist, our suppliers could
refuse to provide key products and services in the future.

In addition to the cash requirements to fund ongoing operations, we have incurred significant professional fees and other costs in connection with the RSA and expect that we will continue to incur significant fees and costs throughout the Chapter 11 proceedings.

Even if we obtain financing under the DIP Credit Agreement, we cannot state with
certainty that our liquidity will be sufficient to allow us to satisfy our
obligations related to the Chapter 11 proceedings or that we will be able to
confirm a Plan with the Bankruptcy Court that allows us to emerge from
bankruptcy. In addition, we will be required to comply with the covenants and
conditions of our DIP Credit Agreement in order to continue to access borrowings
thereunder.

If the Chapter 11 Filings are not completed or the Plan is not consummated
within the timeframe expected, we do not expect to have sufficient liquidity to
fund capital expenditures. The Chapter 11 Filings will constitute an Event of
Default under our credit agreement and Second Lien Notes and the delisting of
our Class A Common Stock will constitute an Event of Default under our Second
Lien Notes. After the Chapter 11 Filings, the creditors will be stayed from
taking any action against the Company as a result of an event of default but
these creditors or other stakeholders may engage in disputes or bring litigation
that would increase the costs of the restructuring or Chapter 11 Filings.


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Working Capital

We define working capital as current assets less current liabilities. At
March 31, 2020 and December 31, 2019, we had a working capital deficit of $312.8
million and a deficit of $19.1 million, respectively. The deficit was primarily
due to the amounts outstanding under the Amended and Restated Credit Agreement
and the Note Purchase Agreement being classified as a current liability.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows for the periods indicated:

                                              Three Months Ended March 31,
                                                2020                2019
                                                     (In thousands)

Net cash provided by operating activities $ 44,583 $ 51,373 Net cash used in investing activities

           (45,314 )            (74,780 )
Net cash provided by financing activities        76,049                

8,902

Net decrease in cash and cash equivalents $ 75,318 $ (14,505 )

Analysis of Cash Flow Changes for the Three Months Ended March 31, 2020 and 2019

Operating activities. Net cash provided by operating activities is primarily
driven by the changes in commodity prices, operating expenses, production
volumes and associated changes in working capital. The decrease in net cash
provided by operating activities of $6.8 million was primarily due to a decrease
in revenues of $11.7 million, an increase in cash related expenses which
decreased our operating cash flows of $5.6 million and a decrease in our loss on
hedge settlements which increased our operating cash flows of $10.4 million.

Investing activities. Net cash used in investing activities for the three months
ended March 31, 2020 included $45.2 million attributable to the development of
oil and natural gas properties and $0.1 million for additions to other property
and equipment. Net cash used in investing activities for the three months
ended March 31, 2019 included $75.8 million attributable to the development of
oil and natural gas properties and $0.1 million for additions to other property
and equipment, all of which was partially offset by the deposit received for the
sale of our oil and gas properties located in Lea County, New Mexico in the
amount of $1.1 million.

Financing activities. Net cash provided by financing activities for the three
months ended March 31, 2020 primarily consisted of borrowings of $96.0 million
under our Amended and Restated Credit Agreement partially offset by $16.0
million of repayments on our Amended and Restated Credit Agreement, and $4.0
million of dividend payments. Net cash provided by financing activities for the
three months ended March 31, 2019 primarily consisted of net borrowings of $13.0
million under our Amended and Restated Credit Agreement partially offset by $3.4
million of dividend payments and $0.6 million of debt issuance costs.

Debt Agreements and Redeemable Preferred Stock

Amended and Restated Credit Agreement. On March 28, 2018, Rosehill Operating and
JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, entered
into the Amended and Restated Credit Agreement to refinance and replace Rosehill
Operating's previous credit facility (the "Previous Credit Facility"). Pursuant
to the terms and conditions of the Amended and Restated Credit Agreement,
Rosehill Operating's line of credit and a letter of credit facility increased
from up to $250 million under the Previous Credit Facility to up to $500 million
under the Amended and Restated Credit Agreement, subject to a borrowing base
that is determined semi-annually by the lenders based upon Rosehill Operating's
financial statements and the estimated value of its oil and gas properties, in
accordance with the lenders' customary practices for oil and gas loans. The
redeterminations occur on April 1 and October 1 of each year. We both have the
right to one interim unscheduled redetermination of the borrowing base between
any two successive scheduled redeterminations. The borrowing base is scheduled
to be automatically reduced upon the issuance or incurrence of debt under senior
unsecured notes or upon Rosehill Operating's or any of its subsidiaries'
disposition of properties or liquidation of hedges in excess of certain
thresholds. We made a $74 million draw on March 19, 2020 as a precautionary
measure in order to increase our cash position and preserve financial
flexibility in light of current uncertainty in the global markets and commodity
prices. After giving effect to this draw, our total outstanding borrowings under
the Amended and Restated Credit Agreement was $340 million and we had no
additional capacity.

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Please read Chronology of Events and Going Concern Assessment within this MD&A
section for details on the following items under the Amended and Restated Credit
Agreement: (i) the RSA and the Forbearance Agreement, (ii) event of default
related to the delivery of audited financial statements (without a going concern
qualification), (iii) the letter from Nasdaq regarding the Company's stock price
trading below the minimum bid price requirement for continued listing and (iv)
restrictions on cash distributions on its Series A Preferred Stock and Series B
Preferred Stock.

The Amended and Restated Credit Agreement requires Rosehill Operating to deliver
unaudited financial statements to the lenders within 45 days after the end of
each fiscal quarter. We can satisfy this requirement by filing our unaudited
financial statements with the SEC within 45 days after the end of each fiscal
quarter. We failed to provide the lenders with unaudited financial statements
and other required certificates and operating reports within 45 days after March
31, 2020, which constitutes a default under the Amended and Restated Credit
Agreement. The Amended and Restated Credit Agreement gives us a 30-day cure
period before it becomes an event of default that will allow the lenders to
require us to pay a portion or all amounts outstanding. However, we were unable
to satisfy these requirements within the cure period. As such, this represented
an event of default under the Amended and Restated Credit Agreement.

The amounts outstanding under the Amended and Restated Credit Agreement are
secured by first priority liens on substantially all of Rosehill Operating's oil
and natural gas properties and associated assets and all of the stock of
Rosehill Operating's material operating subsidiaries that are guarantors of the
Amended and Restated Credit Agreement. There are currently no guarantors under
the Amended and Restated Credit Agreement. If an event of default occurs under
the Amended and Restated Credit Agreement, JPMorgan Chase Bank, N.A. will have
the right to proceed against the pledged capital stock and take control of
substantially all of Rosehill Operating and Rosehill Operating's material
operating subsidiaries that are guarantors' assets. An event of default can
occur under a number of circumstances, including failure to maintain listing of
our Class A Common Stock on a national securities exchange.

Borrowings under the Amended and Restated Credit Agreement will bear interest at
a base rate plus an applicable margin ranging from 1.00% to 2.00% or at LIBO
rate plus an applicable margin ranging from 2.00% to 3.00%. The Amended and
Restated Credit Agreement will mature on August 31, 2022, with an automatic
extension to March 28, 2023 upon the payment in full of the Second Lien Notes if
there is no event of default under the senior secured credit facility during the
time of such extension.

The Amended and Restated Credit Agreement contains various affirmative and
negative covenants. These negative covenants may limit Rosehill Operating's
ability to, among other things: incur additional indebtedness; make loans to
others; make investments; enter into mergers; make or declare dividends or
distributions; enter into commodity hedges exceeding a specified percentage of
Rosehill Operating's expected production; enter into interest rate hedges
exceeding a specified percentage of Rosehill Operating's outstanding
indebtedness; incur liens; sell assets; and engage in certain other transactions
without the prior consent of JPMorgan Chase Bank, N.A. or lenders.

The Amended and Restated Credit Agreement also requires Rosehill Operating to maintain compliance with the following financial ratios:

• a current ratio, which is the ratio of consolidated current assets (including

unused commitments under the Amended and Restated Credit Agreement, but

excluding certain non-cash assets) to consolidated current liabilities

(excluding certain non-cash obligations, current maturities under the Amended

and Restated Credit Agreement and the Note Purchase Agreement (as defined

below)), of not less than 1.0 to 1.0,

• a leverage ratio, which is the ratio of the sum of Total Debt to Annualized

EBITDAX (as such terms are defined in the Amended and Restated Credit

Agreement) for the four fiscal quarters then ended, of not greater than 4.0

to 1.0 (the calculation of which will be modified once the Second Lien Notes

and the Series B Redeemable Preferred Stock are no longer outstanding) and

• a coverage ratio, which is the ratio of EBITDAX to the sum of Interest

Expense plus the aggregate amount of certain Restricted Payments (as such

terms are defined in the Amended and Restated Credit Agreement) made during

the preceding four fiscal quarters, of not less than 2.5 to 1.0 (such ratio

    expiring once the Series B Redeemable Preferred Stock are no longer
    outstanding).



We were in compliance with all financial ratios in the Amended and Restated
Credit Agreement for the measurement period ended March 31, 2020. If we are not
able to generate additional funds or if oil prices do not improve significantly,
we will not be able to comply with our current ratio and leverage ratio covenant
under the Amended and Restated Credit Agreement in future periods.

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The Chapter 11 Filings will constitute an Event of Default under our Amended and
Restated Credit Agreement. The lenders are subject to a forbearance under the
RSA and, after the Chapter 11 Filings, will be stayed from taking any action
against the Company as a result of an event of default under the Amended and
Restated Credit Agreement.

For additional information regarding our Amended and Restated Credit Agreement, see Note 13 - Long-term Debt, net in the condensed consolidated financial statements under Part I, Item 1 of this Quarterly Report on Form 10-Q.

Second Lien Notes. On December 8, 2017, Rosehill Operating issued and sold
$100,000,000 in aggregate principal amount of 10.00% Senior Secured Second Lien
Notes due January 31, 2023 to EIG under and pursuant to the terms of the Note
Purchase Agreement (as amended by the Limited Consent and First Amendment to
Note Purchase Agreement, dated as of March 28, 2018, the "Note Purchase
Agreement"), among Rosehill Operating and us, the Holders and U.S. Bank National
Association, as agent and collateral agent on behalf of the Holders. The Second
Lien Notes were issued and sold to the Holders in a private placement exempt
from the registration requirements under the Securities Act.

Under the Note Purchase Agreement, Rosehill Operating may, at its option, redeem
the Second Lien Notes in whole or in part, together with accrued and unpaid
interest thereon, (i) at any time after December 8, 2019 but on or prior to
December 8, 2020, at a redemption price equal to 103% of the principal amount of
the Second Lien Notes being redeemed, (ii) at any time after December 8, 2020
but on or prior to December 8, 2021, at a redemption price equal to 101.5% of
the principal amount of the Second Lien Notes being redeemed and (iii) at any
time after December 8, 2021, at a redemption price equal to the principal amount
of the Second Lien Notes being redeemed.

The Second Lien Notes may become subject to redemption under certain other
circumstances, including upon the incurrence of non-permitted debt or, subject
to various exceptions, reinvestments rights and prepayment or redemption rights
with respect to other debt or equity of Rosehill Operating, upon an asset sale,
hedge termination or casualty event. Rosehill Operating will be further required
to make an offer to redeem the Second Lien Notes upon a Change in Control (as
defined in the Note Purchase Agreement) at a redemption price equal to 101% of
the principal amount being redeemed. Other than in connection with a Change in
Control or casualty event, the redemption prices described in the foregoing
paragraph shall also apply, at such times and to the extent set forth therein,
to any mandatory redemption of the Second Lien Notes or any acceleration of the
Second Lien Notes prior to the stated maturity thereof upon the occurrence of an
event of default.

The Note Purchase Agreement requires Rosehill Operating to maintain a leverage
ratio, which is the ratio of the sum of all of Rosehill Operating's Total Debt
to Annualized EBITDAX (as such terms are defined in the Note Purchase Agreement)
for the four fiscal quarters then ended, of not greater than 4.00 to 1.00. We
were in compliance with the leverage ratio for the measurement period ended
March 31, 2020. If we are not able to generate additional funds or if oil prices
do not improve significantly, we will not be able to comply with our leverage
ratio covenant under the Note Purchase Agreement in future periods. Please read
Chronology of Events and Going Concern Assessment within this MD&A section for
details on the event of default related to the delivery of audited financial
statements (without a going concern qualification).

The Note Purchase Agreement requires us to deliver unaudited financial
statements to the lenders within 45 days after the end of each fiscal quarter.
We can satisfy this requirement by filing unaudited financial statements of
Rosehill Resources with the SEC within 45 days after the end of each fiscal
quarter. We failed to provide the lenders with unaudited financial statements
and other required certificates and operating reports within 45 days after March
31, 2020, which constituted a default under the Note Purchase Agreement. The
Note Purchase Agreement gives us a 30-day cure period before it becomes an event
of default that will allow the lenders to require us to redeem a portion or all
of the notes outstanding. However, we were unable to able to satisfy these
requirements within this cure period. As such, this represented an event of
default under the Note Purchase Agreement.

The Note Purchase Agreement contains various affirmative and negative covenants,
events of default and other terms and provisions that are based largely on the
Amended and Restated Credit Agreement, with a number of important modifications
reflecting the second lien nature of the Second Lien Notes and certain other
terms that were agreed to with the Holders. The negative covenants may limit
Rosehill Operating's ability to, among other things, incur additional
indebtedness (including pursuant to senior unsecured notes), make investments,
make or declare dividends or distributions, redeem its preferred equity, acquire
or dispose of oil and gas properties and other assets or engage in certain other
transactions without the prior consent of the Holders, subject to various
exceptions, qualifications and value thresholds. Rosehill Operating is also
required to meet minimum commodity hedging levels based on its expected
production on an ongoing basis. Any event or condition that causes any debt
under the Amended and Restated Credit Agreement becoming due prior to its
scheduled maturity, with certain exceptions, including borrowing base
deficiencies, is an event of default under the Note Purchase Agreement.


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We are subject to certain restrictions under the Note Purchase Agreement,
including (without limitation) a negative pledge with respect to our equity
interests in Rosehill Operating and a contingent obligation to guarantee the
Second Lien Notes upon request by the Holders in the event that we incur debt
obligations. The obligations of Rosehill Operating under the Note Purchase
Agreement are secured on a second-lien basis by the same collateral that secures
its first-lien obligations. In connection with the Note Purchase Agreement,
Rosehill Operating granted second-lien security interests over additional
collateral to meet the minimum mortgage requirements under the Note Purchase
Agreement.

The Chapter 11 Filings and the delisting of our Class A Common Stock will
constitute Events of Default under our Second Lien Notes. The holders of the
Second Lien Notes are subject to a forbearance under the RSA and, after the
Chapter 11 Filings, will be stayed from taking any action against the Company as
a result of an event of default under the Second Lien Notes.

Series B Preferred Stock. On December 8, 2017, in connection with the White Wolf
Acquisition, we entered into the Series B Preferred Stock Agreement to issue
150,000 shares of our Series B Preferred Stock, for an aggregate purchase price
of $150.0 million, less transaction costs, advisory and up-front fees of
approximately $10.0 million to certain private funds and accounts managed by
EIG.

Holders of the Series B Preferred Stock are entitled to receive, when, as and if
declared by our Board or a designated committee of the Board, cumulative
dividends in cash, at a rate of 10.00% per annum on the $1,000 liquidation
preference per share of Series B Preferred Stock, payable quarterly in arrears
on January 15, April 15, July 15 and October 15 of each year, commencing on
January 15, 2018. Our Amended and Restated Credit Agreement restricts our cash
distributions to an amount not to exceed $25.0 million on our Series B Preferred
Stock in any fiscal year. Such distributions on our Series B Preferred Stock can
only be made so long as both before and immediately following such
distributions, (i) we are not in any default under our Amended and Restated
Credit Agreement, (ii) our unused borrowing capacity is equal to or greater than
20% of the committed borrowing capacity and (iii) our ratio of Total Debt to
EBITDAX is not greater than 3.5 to 1.0. Based on the default and lack of unused
borrowing capacity under our Amended and Restated Credit Agreement, we were
restricted from paying dividends on our Series B Preferred Stock and therefore
did not declare and pay cash dividends on our Series B Preferred Stock that were
due April 15, 2020. Failure to pay dividends on the Series B Preferred Stock
results in the following:

• Upon the occurrence of not paying a dividend, the dividend rate will increase

    to 12% per annum and will remain at 12% per annum until all applicable
    quarterly dividends have been fully paid and are current, at which time a
    dividend rate of 10% per annum will once again apply.

• Upon the occurrence of not paying a dividend with respect to three out of any

four consecutive quarters or failing to pay a dividend six times (whether or

not consecutive) at anytime the Series B Preferred Stock is outstanding will

entitle the holders of the Series B Preferred Stock to a seat on the Board of

Directors and the right to approve (a) all indebtedness by us if such

indebtedness would cause our Leverage Ratio (as defined in the Series B

Certificate of Designation) to exceed 3.25 to 1.00, (b) any budget or budget

amendments and (c) any capital expenditures in excess of $0.5 million.

• Upon the occurrence of not paying a dividend for a period of nine months

consecutive months, the holders of the Series B Preferred Stock may elect to

cause us to redeem all or a portion of the Series B Preferred Stock.

Holders of the Series B Preferred Stock have no voting rights, but have certain
consent rights with respect to the taking of certain corporate actions by us.
Upon our voluntary or involuntary liquidation, winding-up or dissolution, each
holder of Series B Preferred Stock will be entitled to receive the Base Return
Amount (as defined in the Series B Preferred Stock Agreement) plus accrued and
unpaid dividends.


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In addition to the 10.00% per annum cumulative dividend holders of the Series B
Preferred Stock are entitled to receive, upon redemption of the Series B
Preferred Stock, a guaranteed base return on the initial 150,000 shares
purchased in an amount equal to (x) $1,500 per share of Series B Preferred Stock
and (y) an amount necessary to achieve the Base Return Amount with respect to
such shares of Series B Preferred Stock, minus all dividends paid on shares of
Series B Preferred Stock, including dividends paid-in-kind, and minus up-front
fees incurred at issuance of the Series B Preferred Stock. The shares of Series
B Preferred Stock are redeemable at the election of the holders on or after
December 8, 2023 and upon certain conditions and at any time at our option. As
the holders of Series B Preferred Stock have an option to redeem the Series B
Preferred Stock at a future date, the Series B Preferred Stock is included
in temporary, or "mezzanine" equity, between total liabilities and stockholders'
equity on the Condensed Consolidated Balance Sheets.  The Series B Preferred
Stock, while not currently redeemable at the option of the holders, is
remeasured each reporting period by accreting the initial value to the estimated
redemption value that will achieve a 16% IRR on December 8, 2023 when the Series
B Preferred Stock is redeemable in whole or in part at the election of the
holders of Series B Preferred Stock. The accretion is considered a deemed
dividend, which increases the carrying value of the Series B Preferred Stock on
the Condensed Consolidated Balance Sheets and is included within preferred
dividends on the Condensed Consolidated Statements of Operations. If the Series
B Preferred Stock would have been redeemed on March 31, 2020, the Base Return
Amount was approximately $195.2 million, which was higher than the redemption
amount accrued, and will be reduced by subsequent dividend payments. Any
redemption must be made out of funds legally available therefor.

In the event of a Change of Control (which includes failure to maintain the
listing of our Class A Common Stock on a national securities exchange), we shall
redeem in cash all of the outstanding shares of Series B Preferred Stock,
excluding Series B PIK Shares, for a price per share equal to the Base Return
Amount and all Series B PIK Shares at the purchase price of $1,000 per share. We
assessed the Change of Control feature and determined that the redemption of the
outstanding shares of Series B Preferred Stock, excluding Series B PIK Shares,
for a price per share equal to the Base Return Amount was an embedded derivative
that required bifurcation and was accounted for at fair value. Because we
recorded the Series B Preferred Stock at its current redemption value as of
March 31, 2020, there was no value attributed to the bifurcated embedded
derivative. On March 23, 2020, we received a letter from Nasdaq indicating that
for the 30 consecutive business days ending March 20, 2020, the bid price for
our common stock had closed below the $1.00 per share minimum bid price
requirement for continued listing on The Nasdaq Capital Market under Nasdaq
Listing Rule 5550(a)(2). Under Nasdaq Listing Rule 5810(c)(3)(A), we have 180
calendar days to regain compliance by meeting the continued listing standard. To
regain compliance, the closing bid price of our common stock must meet or exceed
$1.00 per share for a minimum of ten consecutive business days during the 180
calendar day period. In April 2020, we were notified by Nasdaq that it had
tolled the compliance period from April 16, 2020 through June 30, 2020, in light
of market conditions resulting from the COVID-19 pandemic. Since we had 156
calendar days remaining in our compliance period as of April 16, 2020, we will
still have 156 calendar days from July 1, 2020, or until December 3, 2020, to
regain compliance. We cannot guarantee that we will be able to maintain listing
of our Class A Common Stock, Class A Common Stock Public Units, or Public
Warrants on The Nasdaq Capital Market.

The delisting of our Class A Common Stock will constitute Events of Default under our Series B Preferred Stock, but, after the Chapter 11 Filings, the holders will be stayed from taking any action against the Company as a result of an event of default under the Series B Preferred Stock.

Off-Balance Sheet Arrangements

As of March 31, 2020, we had no off-balance sheet arrangements or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party.

Critical Accounting Policies and Estimates

Our Annual Report on Form 10-K contains a discussion, which is incorporated
herein by reference, of the accounting estimates that we believe are critical to
the reporting of our financial position and operating results and that require
management's judgment. Our more significant policies and estimates include:

• Successful efforts method of accounting for oil and natural gas activities

• Impairment of oil and natural gas properties

• Depreciation, depletion and amortization for oil and gas properties

• Oil and natural gas reserve quantities

• Commodity derivative instruments

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• Asset retirement obligations

• Income Taxes

• Tax Receivable Agreement

This Quarterly Report on Form 10-Q should be read together with the discussion
contained in our Annual Report on Form 10-K regarding these critical accounting
policies. There have been no material changes to our critical accounting
policies from those described in our Annual Report on Form 10-K.

Recently Issued Accounting Pronouncements

Please refer to Note 2 - Summary of Significant Accounting Policies and Recently
Issued Accounting Standards in the condensed consolidated financial statements
under Part I, Item 1 of this Quarterly Report on Form 10-Q for a discussion of
recent accounting pronouncements and their anticipated effect on us.





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