The following discussion is intended to assist in understanding our results of
operations for the three and nine months ended September 30, 2020 (Successor)
and 2019 (Predecessor) and should be read in conjunction with our unaudited
condensed consolidated financial statements and the notes thereto included in
this Quarterly Report on Form 10-Q and with the consolidated financial
statements, notes and management's discussion and analysis of financial
condition and results of operations included in our Annual Report on Form 10-K
for the fiscal year ended December 31, 2019 (Successor).
Certain prior year financial statements are not comparable to our current year
financial statements due to the adoption of fresh-start accounting. References
to "Successor" or "Successor Company" relate to the financial position and
results of operations of the reorganized Company subsequent to October 1, 2019.
References to "Predecessor" or "Predecessor Company" relate to the financial
position and results of operations of the Company prior to, and including,
October 1, 2019.
Statements in this discussion may be forward-looking. These forward-looking
statements involve risks and uncertainties, including those discussed below,
which could cause actual results to differ from those expressed. For more
information, see "Special note regarding forward-looking statements."
Overview
We are an independent energy company focused on the acquisition, production,
exploration and development of onshore liquids-rich oil and natural gas assets
in the United States. During 2017 (Predecessor), we acquired certain properties
in the Delaware Basin and divested our assets located in the Williston Basin in
North Dakota and in the El Halcón area of East Texas. As a result, our
properties and drilling activities are currently focused in the Delaware Basin,
where we have an extensive drilling inventory that we believe offers attractive
long-term economics.
During the first nine months of 2020 (Successor), production averaged 16,712
Boe/d compared to average production of 17,209 Boe/d during the first nine
months of 2019 (Predecessor). Our average daily oil and natural gas production
decreased in the first nine months of 2020 (Successor) when compared to the same
period in the prior year primarily due to our temporary shut-in of a portion of
producing wells across all our operating areas in May and June 2020 as a
consequence of low oil prices. Estimated downtime associated with these
temporary shut-ins was approximately 1,800 Boe/d for the first nine months of
2020 (Successor). The production decline caused by temporary shut-ins in the
current year period was partially offset by new wells put online since the prior
year. For the nine months ended September 30, 2020 (Successor), we drilled and
cased 4.0 gross (4.0 net) operated wells, completed 5.0 gross (4.3 net) operated
wells, and put online 7.0 gross (6.3 net) operated wells.
Our financial results depend upon many factors, but are largely driven by the
volume of our oil and natural gas production and the price that we receive for
that production. Our production volumes will decline as reserves are depleted
unless we expend capital in successful development and exploration activities or
acquire properties with existing production. The amount we realize for our
production depends predominantly upon commodity prices, which are affected by
changes in market demand and supply, as impacted by overall economic activity,
weather, transportation take-away capacity constraints, inventory storage
levels, basis differentials and other factors. Accordingly, finding and
developing oil and natural gas reserves at economical costs is critical to our
long-term success.
Oil and natural gas prices are inherently volatile and sustained lower commodity
prices could have a material impact upon our full cost ceiling test calculation.
The ceiling test calculation dictates that we use the unweighted arithmetic
average price of crude oil and natural gas as of the first day of each month for
the 12-month period ending at the balance sheet date. Using the crude oil price
for October 2020 of $42.37 per barrel, and holding it constant for two months to
create a trailing 12-month period of average prices, that is more reflective of
recent price trends, our ceiling amount related to the net book value of our oil
and natural gas properties would have been reduced and would have generated an
additional impairment of $77.5 million, holding all other inputs and factors
constant. In addition to commodity prices, our production rates, levels of
proved reserves, future development costs, transfers of unevaluated properties
to our full
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cost pool, capital spending and other factors will determine our actual ceiling
test calculation and impairment analyses in future periods.
Recent Developments
Risk and Uncertainties
We are continuously monitoring the current and potential impacts of the novel
coronavirus (COVID-19) pandemic on our business, including how it has and may
continue to impact our operations, financial results, liquidity, contractors,
customers, employees and vendors, and taking appropriate actions in response,
including reducing capital expenditures, temporarily shutting-in producing
wells, and implementing various measures to ensure the continued operation of
our business in a safe and secure manner. COVID-19 and governmental actions to
contain the pandemic have contributed to an economic downturn, reduced demand
for oil and natural gas and, together with a price war between the Organization
of Petroleum Exporting Countries (OPEC)/Saudi Arabia and Russia, depressed oil
and natural gas prices to historically low levels. Although OPEC and Russia
agreed in April to reduce production, downward pressure on prices has continued
and could continue for the foreseeable future, particularly given concerns over
the impacts of the current economic downturn on demand. We are unable to predict
the effect that these events will have on our business and financial condition
due to numerous uncertainties, including the severity and duration of the
COVID-19 outbreak and the impacts that governmental or other actions taken to
limit the extent and duration of the outbreak, in conjunction with economic
conditions, will have on our business, demand for oil and natural gas, and oil
and natural gas prices. The health of our employees, contractors and vendors,
and our ability to meet staffing needs in our operations and critical functions
cannot be predicted, nor can the impact on our customers, vendors and
contractors. Any material effect on these parties could adversely impact us.
These and other factors could affect the Company's operations, earnings and cash
flows and could cause our results to not be comparable to those of the same
period in previous years. For example, we realized lower revenue as a result of
commodity price declines, which began in March 2020. In response to low
commodity prices, we temporarily shut-in producing wells in May and June 2020,
which further contributed to lower revenues in the current year. Additionally,
we incurred ceiling test impairments, which were primarily driven by a decline
in the average pricing used in the valuation of our reserves. The results
presented in this Form 10-Q are not necessarily indicative of future operating
results. For further information regarding the actual and potential impacts of
COVID-19 on us, see "Risk Factors" in Item 1A of this Quarterly Report on Form
10-Q.
Acid Gas Injection Well Permits
During the nine months ended September 30, 2020 (Successor), we received permits
from the Texas Railroad Commission and the Texas Commission on Environmental
Quality to construct and operate an acid gas injection well (AGI) by converting
an existing producing gas well. AGI can provide a more cost effective
alternative to sour gas treating. We are currently evaluating options for
development of an AGI facility, including, but not limited to, divestiture of
the assets with an associated third party treating arrangement for our sour gas
production.
Successor Senior Revolving Credit Facility
On October 29, 2020 (Successor), we entered into the Third Amendment to Senior
Secured Revolving Credit Agreement and Limited Waiver (the Third Amendment). The
Third Amendment, among other things, sets the borrowing base to $190 million as
of November 1, 2020, which eliminated the final monthly reduction of $5.0
million required under the Second Amendment (defined below). The Third Amendment
also reduces the amount available for the issuance of letters of credit to $25.0
million and amends certain covenants including, but not limited to, covenants
relating to increasing the minimum mortgaged total value of proved borrowing
base properties from 85% to 90%. Additionally, the Third Amendment provides for
new covenants that, among other things, require us to enter into required swap
agreements representing not less than 65% of our reasonably anticipated
projected production from the proved reserves classified as developed producing
reserves for a period from the Third Amendment effective date through at least
December 31, 2022 and prohibit no more than $3 million of our uncontested
accounts payable or accrued expenses, liabilities or other obligations from
remaining outstanding for longer than 90 days. Pursuant to the Third Amendment,
the administrative agent and the lenders consented to a waiver of the Current
Ratio (as defined in the
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Senior Credit Agreement) for the fiscal quarter ended September 30, 2020 and
also suspended testing of the Current Ratio until the fiscal quarter ending
December 31, 2021.
On July 31, 2020 (Successor), we entered into the Limited Waiver to Senior
Secured Revolving Credit Agreement (the Waiver) in which, the lenders consented
to waive maintenance of a Current Ratio (as defined in the Senior Credit
Agreement) of not less than 1.00 to 1.00 as of the fiscal quarter ended June 30,
2020. Our failure to comply with the Current Ratio for the three months ended
June 30, 2020 (Successor) was primarily the result of our decision to shut in
certain production due to low oil prices coupled with capital spending required
to maintain certain of our oil and gas leasehold interests.
On April 30, 2020 (Successor), we entered into the Second Amendment to the
Senior Credit Agreement (Second Amendment) which among other things, (i) reduced
the borrowing base to $200.0 million effective from April 30, 2020, which was
then reduced by $5.0 million monthly starting September 1, 2020 until November
1, 2020, so that the borrowing base was scheduled to be $185.0 million on
November 1, 2020, provided the borrowing base redetermination scheduled for
November 1, 2020 occurred pursuant to the terms of the Senior Credit Agreement,
(ii) increased interest margins to 1.50% to 2.50% for ABR-based loans and 2.50%
to 3.50% for Eurodollar-based loans, (iii) provided that should our Consolidated
Cash Balance (as defined pursuant to the Second Amendment) exceed $10.0 million,
such amounts shall be used to prepay any borrowings under the Senior Credit
Agreement and thereafter, to the extent of any uncollateralized letters of
credit exposure, shall be cash collateralized in accordance with the Senior
Credit Agreement and (iv) allowed for a replacement benchmark rate to the London
Interbank Offered Rate (which may include SOFR, Compounded SOFR or Term SOFR).
The Second Amendment also added provisions related to a loan incurred by us
under the Paycheck Protection Program of the Coronavirus Aid, Relief, and
Economic Security Act (the CARES Act). We used, and the Second Amendment
required us to use, the loan proceeds for CARES Forgivable Uses under the CARES
Act. Additionally, the Second Amendment waived, for the fiscal quarter ended
June 30, 2020, that we comply with the requirement under the Senior Credit
Agreement that we unwind certain swap agreements for which settlement payments
were calculated in such fiscal quarter to exceed 100% of actual production.
Paycheck Protection Program Loan
On April 16, 2020 (Successor), we entered into a promissory note (the PPP Loan)
for a principal amount of approximately $2.2 million from Bank of Montreal under
the Paycheck Protection Program of the CARES Act, which is administered by the
U.S. Small Business Administration. Pursuant to the terms of the CARES Act, the
proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent
or utility costs. The PPP Loan bears interest at a rate of 1.0% per annum. We
are required to pay principal and interest installments of $0.1 million monthly
beginning November 16, 2020. The maturity date of the PPP Loan is April 16,
2022.
We may elect, at our option, to prepay 20% or less of the borrowings outstanding
under the PPP Loan without premium or penalty, and without notice. Prepayments
of more than 20% of the outstanding borrowings require written advanced notice
and payment of accrued interest. The PPP Loan contains certain events of default
including non-payment, breach of representations and warranties, cross-defaults
to other loans with the lender or to material indebtedness, voluntary or
involuntary bankruptcy, judgments and change in control.
Under the terms of the CARES Act, we can apply for and be granted forgiveness
for all or a portion of the PPP Loan. Such forgiveness will be determined,
subject to limitations, based on the use of loan proceeds in accordance with the
terms of the CARES Act during the eight week period after loan origination and
the maintenance or achievement of certain employee levels. We believe we are
eligible for, and are currently pursuing, forgiveness of the PPP Loan in
accordance with the requirements and limitations under the CARES Act; however,
no assurance can be provided that forgiveness of any portion of the PPP Loan
will be obtained.
Listing of our Common Stock on NYSE American
Our Predecessor common stock was previously listed on the New York Stock
Exchange (NYSE) under the symbol "HK." As a result of our failure to satisfy the
continued listing requirements of the NYSE, on July 22, 2019, our
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Predecessor common stock was delisted from the NYSE. Effective February 20,
2020, we commenced trading on the NYSE American exchange under the symbol
"BATL."
Capital Resources and Liquidity
In March 2020 (Successor), the World Health Organization declared the outbreak
of COVID-19 a pandemic. The COVID-19 outbreak and associated government
restrictions significantly impacted economic activity and markets and
dramatically reduced current and anticipated demand for oil and natural gas at
the same time that supply was maintained at high levels due to a price and
market share war involving the OPEC/Saudi Arabia and Russia, all of which
adversely impacted the prices we received for our production during the nine
months ended September 30, 2020 (Successor). We realized lower revenue as a
result of these commodity price declines, which began in March 2020 (Successor).
In response to low commodity prices, we temporarily shut-in producing wells in
May and June 2020 (Successor), which further contributed to lower revenues in
the current year. Additionally, we incurred ceiling test impairments, which were
primarily driven by a decline in the average pricing used in the valuation of
our reserves.
Continued actual or anticipated declines in domestic or foreign economic
activity or growth rates, regional or worldwide increases in tariffs or other
trade restrictions, turmoil affecting the U.S. or global financial system and
markets and a severe economic contraction either regionally or worldwide,
resulting from current efforts to contain the COVID-19 coronavirus or other
factors, could materially affect our business and financial condition and impact
our ability to finance operations by worsening the actual or anticipated future
drop in worldwide oil demand, negatively impacting the price received for oil
and natural gas production, adversely impacting our ability to comply with
covenants in our Senior Credit Agreement or causing our lenders to reduce the
borrowing base under our Senior Credit Agreement. Negative economic conditions
could also adversely affect the collectability of our trade receivables or
performance by our vendors and suppliers or cause our commodity hedging
arrangements to be ineffective if our counterparties are unable to perform their
obligations. All of the foregoing may adversely affect our business, financial
condition, results of operations, cash flows and, potentially, compliance with
the covenants contained in, and borrowing capacity under, our Senior Credit
Agreement.
Our 2020 drilling and completion budget, originally approved by our board in
December 2019, contemplated running one operated rig in the Delaware Basin
during the year. That budget contemplated spending approximately $123 million to
$138 million in capital expenditures, including drilling, completions, support
infrastructure and other capital costs, to drill seven to ten gross operated
wells and to put online 12 to 14 gross operated wells during the year. We
continuously monitor changes in market conditions and adapt our operational
plans as necessary in order to maintain financial flexibility, preserve acreage,
and meet our contractual obligations. Accordingly, in March 2020, as a result of
changes in market conditions and commodity prices, we scaled back our capital
operations and spending. The rate of our expenditures has declined as we have
progressed through the year and we expect our anticipated full year 2020 capital
expenditures will be approximately $80 million to $84 million, subject to our
continuing evaluation of market conditions and the risks and uncertainties
affecting our business detailed elsewhere in this report.
Our near-term capital spending requirements are expected to be funded with cash
and cash equivalents on hand, cash flows from operations, and borrowings under
our Senior Credit Agreement, which has a current borrowing base of $190.0
million. Amounts borrowed under the Senior Credit Agreement will mature on
October 8, 2024. At September 30, 2020 (Successor), under the then-effective
borrowing base of $195.0 million, we had $178.0 million of indebtedness
outstanding and approximately $4.7 million letters of credit outstanding under
the Senior Credit Agreement, resulting in $12.3 million of borrowing capacity.
Under the Third Amendment, our borrowing base was recently affirmed at $190.0
million; however, we currently expect availability under our Senior Credit
Agreement to be limited through at least the second quarter of 2021. The next
redetermination is scheduled for the spring of 2021. If our borrowing base is
reduced upon a redetermination, our resulting liquidity could be insufficient to
fund our business and operations and the reduction could result in a borrowing
base deficiency, which would require us to repay any amount outstanding in
excess of the borrowing base. As part of our ongoing efforts to manage our
business and liquidity, we are in regular contact with our lenders regarding
these and other matters relating to the Senior Credit Agreement and, in
parallel, are exploring alternative means to maintain our access to sufficient
capital to fund our business, including refinancings, asset sales, and
additional means to reduce our capital requirements. While we believe that
alternatives to maintain compliance or to
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replace our Senior Credit Agreement are available to us should they become
necessary, there can be no assurance in this regard.
The Senior Credit Agreement contains certain financial covenants, including
maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the
Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current
Ratio (as defined in the Senior Credit Agreement) of not less than 1.00:1.00. We
have recently, and in the past, obtained amendments to the covenants under our
revolving credit agreements in circumstances where we anticipated that it might
be challenging for us to comply with the financial covenants for a particular
period of time. Changes in the level and timing of our production, drilling and
completion costs, the cost and availability of transportation for our production
and other factors varying from our expectations can affect our ability to comply
with the covenants under our Senior Credit Agreement. As a consequence, we
endeavor to anticipate potential covenant compliance issues and work with the
lenders under our Senior Credit Agreement to address any such issues ahead of
time.
The current depression in oil and natural gas prices and our decision to
temporarily shut-in a portion of our production in response to those market
conditions adversely impacted our cash flows, which, combined with cash
requirements associated with capital-intensive oil and gas development projects
undertaken in late 2019 and early 2020, led to challenges in compliance with the
Current Ratio under the Senior Credit Agreement for the fiscal quarter ended
June 30, 2020. Thus, on July 31, 2020 (Successor), we entered into the Waiver,
in which the lenders consented to waive maintenance of the Current Ratio (as
defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 for the
fiscal quarter ended June 30, 2020. In conjunction with the fall borrowing base
redetermination process, and due to a decline in the value associated with our
derivative contracts, we pursued additional relief from our lenders in regards
to the Current Ratio. Pursuant to the Third Amendment, on October 29, 2020, the
lenders waived maintenance of the Current Ratio for the fiscal quarters ending
September 30, 2020 and suspends testing of the Current Ratio until the fiscal
quarter ending December 31, 2021. As of September 30, 2020 (Successor), after
giving effect to the Third Amendment, we were in compliance with the financial
covenants under the Senior Credit Agreement.
In prior years, we have also obtained waivers and amendments for optional
covenant violations. For instance, our strategic decision to transform into a
pure-play, single basin company focused on the Delaware Basin in West Texas
resulted in us divesting our producing properties located in other areas and
acquiring primarily undeveloped acreage in the Delaware Basin. Our drilling
activities once we acquired these assets required significant capital
expenditure outlays to replenish production and related EBITDA from the divested
producing properties. These and other factors adversely impacted our ability to
comply with our debt covenants under the Predecessor Credit Agreement by
reducing our production, reserves and EBITDA on a current and a pro forma
historical basis, while making us more susceptible to fluctuations in
performance and compliance more challenging. In addition, we encountered certain
operational difficulties that impacted our ability to comply, including,
elevated levels of hydrogen sulfide in the natural gas produced from our
Monument Draw wells and limited and expensive treatment and transportation
options. Severance payments to executives in 2019 also impacted our ability to
comply with our financial covenants.
While we have largely been successful in obtaining modifications of our
covenants as needed, there can be no assurance that we will be successful in the
future. In the event we are not successful, there is no assurance that we will
be successful in implementing alternatives that allow us to maintain compliance
with our covenants or that we will be successful in obtaining alternative
financing that provides us with the liquidity that we need to operate our
business. Even if successful, alternative sources of financing could prove more
expensive than borrowing under our Senior Credit Agreement.
When commodity prices decline significantly, as they have recently, our ability
to finance our capital budget and operations may be adversely impacted. We use
derivative instruments to provide partial protection against declines in oil,
natural gas and natural gas liquids prices, however, the total volumes we
typically hedge are less than our expected production, vary from period to
period based on our view of current and future market conditions and generally
extend up to only approximately 30 months. These limitations result in our
liquidity being susceptible to commodity price declines. Additionally, while
intended to reduce the effects of volatile commodity prices, derivative
transactions may limit our potential gains and increase our potential losses if
commodity prices were to rise substantially over the price established by the
hedge. Our Senior Credit Agreement contains minimum hedging requirements.
Pursuant to the Third Amendment, we are required to hedge at least 65% of
anticipated production from proved developed producing reserves
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through December 31, 2022. Our hedge policies and objectives may change
significantly as our operational profile changes and/or commodities prices
change. We do not enter into derivative contracts for speculative trading
purposes.
Our future capital resources and liquidity depend on our success in developing
our leasehold interests, growing our reserves and production and finding
additional reserves. Cash is required to fund capital expenditures necessary to
offset inherent declines in our production and proven reserves, which is typical
in the capital-intensive oil and natural gas industry. We strive to maintain
financial flexibility while pursuing our drilling plans and may access capital
markets, pursue joint ventures, sell assets and engage in other transactions as
necessary to, among other things, maintain borrowing capacity, facilitate
drilling on our undeveloped acreage position and permit us to selectively expand
our acreage. Our ability to complete such transactions and maintain or increase
our borrowing base is subject to a number of variables, including our level of
oil and natural gas production, proved reserves and commodity prices, the amount
and cost of our indebtedness, as well as various economic and market conditions
that have historically affected the oil and natural gas industry. Even if we are
otherwise successful in growing our proved reserves and production, if oil and
natural gas prices decline for a sustained period of time, our ability to fund
our capital expenditures, complete acquisitions, reduce debt, meet our financial
obligations and become profitable may be materially impacted.
Cash Flow
During the nine months ended September 30, 2020 (Successor), operating cash
flows supplemented with borrowings under our revolving credit agreement were
used to fund our drilling and completion programs. See "Results of Operations"
for a review of the impact of prices and volumes on operating revenues.
Net increase (decrease) in cash, cash equivalents and restricted cash is
summarized as follows (in thousands):
Successor Predecessor
Nine Months Nine Months
Ended Ended
September 30, 2020 September 30, 2019
Cash flows provided by (used in) operating $ $
activities 47,878 (33,233)
Cash flows provided by (used in) investing
activities (92,503) (254,417)
Cash flows provided by (used in) financing
activities 36,177 257,793
Net increase (decrease) in cash, cash equivalents $ $
and restricted cash (8,448) (29,857)
Operating Activities. Net cash flows provided by operating activities for the
nine months ended September 30, 2020 (Successor) and net cash flows used in
operating activities for the nine months ended September 30, 2019 (Predecessor)
were $47.9 million and $33.2 million, respectively.
Operating cash flows for the nine months ended September 30, 2020 (Successor)
increased from the comparable prior year period due to decreases in our
operating expenses associated with our focus on efficiencies and cost savings
and a decrease in interest expense associated with lower outstanding debt due to
our chapter 11 bankruptcy. In addition, realized gains from derivative contracts
were higher in the nine months ended September 30, 2020, which included the
early termination of certain derivative contracts. During the nine months ended
September 30, 2020 (Successor), we terminated certain derivative contracts in
advance of their natural expiration dates and received net proceeds of
approximately $22.9 million during the period. These increases to operating cash
flows in 2020 were partially offset by decreased oil and natural gas revenues as
a result of lower realized commodity prices and lower production volumes than
the comparable prior year period.
Operating cash flows for the nine months ended September 30, 2019 (Predecessor)
decreased from the comparable prior year period due to increases in our
operating expenses, primarily severances paid to executives, reorganization
costs, and third party water hauling and disposal costs.
Investing Activities. Net cash flows used in investing activities for the nine
months ended September 30, 2020 (Successor) and 2019 (Predecessor) were
approximately $92.5 million and $254.4 million, respectively.
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During the nine months ended September 30, 2020 (Successor), we spent $96.5
million on oil and natural gas capital expenditures, of which $62.9 million
related to drilling and completion costs and $32.1 million related to the
development of our treating equipment and gathering support infrastructure. We
received $3.5 million in proceeds from the sale of oil and natural gas
properties. In addition, we received $0.5 million in insurance proceeds
associated with a casualty loss on our support infrastructure.
During the nine months ended September 30, 2019 (Predecessor), we spent
$167.2 million on oil and natural gas capital expenditures, of which
$158.6 million related to drilling and completion costs. We also spent
approximately $85.6 million on capital expenditures related to the development
of our natural gas treating equipment and our gathering support infrastructure.
Financing Activities. Net cash flows provided by financing activities for the
nine months ended September 30, 2020 (Successor) and 2019 (Predecessor) were
$36.2 million and $257.8 million, respectively.
During the nine months ended September 30, 2020 (Successor), net borrowings of
$34.0 million under our Senior Credit Agreement were used to fund our drilling
and completions program and the development of our treating equipment and
gathering support facilities. We also borrowed $2.2 million under the PPP Loan
to fund payroll costs, rent and utilities.
During the nine months ended September 30, 2019 (Predecessor), net borrowings of
$35.0 million under our debtor-in-possession junior secured term credit facility
(DIP Facility) and $223.2 million under our Predecessor Credit Agreement were
used to fund our drilling and completions program, as well as the development of
our treating infrastructure and our gathering support infrastructure.
Senior Revolving Credit Facility
On October 8, 2019, we entered into the Senior Credit Agreement with Bank of
Montreal, as administrative agent, and certain other financial institutions
party thereto, as lenders. The Senior Credit Agreement, as amended, provides for
a $750.0 million senior secured reserve-based revolving credit facility with a
current borrowing base of $190.0 million. A portion of the Senior Credit
Agreement, in the amount of $25.0 million, is available for the issuance of
letters of credit. The maturity date of the Senior Credit Agreement is October
8, 2024. Redeterminations will occur semi-annually on May 1 and November 1, with
the lenders and us each having the right to one interim unscheduled
redetermination between any two consecutive semi-annual redeterminations. The
borrowing base takes into account the estimated value of our oil and natural gas
properties, proved reserves, total indebtedness, and other relevant factors
consistent with customary oil and natural gas lending criteria. Amounts
outstanding under the Senior Credit Agreement bear interest at specified margins
over the base rate of 1.50% to 2.50% for ABR-based loans or at specified margins
over LIBOR of 2.50% to 3.50% for Eurodollar-based loans, which margins may be
increased one-time by not more than 50 basis points per annum if necessary in
order to successfully syndicate the Senior Credit Agreement. These margins
fluctuate based on our utilization of the facility.
We may elect, at our option, to prepay any borrowings outstanding under the
Senior Credit Agreement without premium or penalty, except with respect to any
break funding payments which may be payable pursuant to the terms of the Senior
Credit Agreement. We may be required to make mandatory prepayments of the
outstanding borrowings under the Senior Credit Agreement in connection with
certain borrowing base deficiencies, including deficiencies which may arise in
connection with a borrowing base redetermination, an asset disposition or swap
terminations attributable in the aggregate to more than ten percent (10%) of the
then-effective borrowing base. Amounts outstanding under the Senior Credit
Agreement are guaranteed by our direct and indirect subsidiaries and secured by
a security interest in substantially all of the assets of us and our
subsidiaries.
The Senior Credit Agreement contains certain events of default, including
non-payment; breaches of representation and warranties; non-compliance with
covenants; cross-defaults to material indebtedness; voluntary or involuntary
bankruptcy; judgments and change in control. The Senior Credit Agreement also
contains certain financial covenants, including maintenance of (i) a Total Net
Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not
greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior
Credit Agreement) of not less than 1.00:1.00.
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On October 29, 2020 (Successor),we entered into the Third Amendment. The Third
Amendment, among other things, sets the borrowing base to $190 million as of
November 1, 2020, which eliminated the final monthly reduction of $5.0 million
required under the Second Amendment. The Third Amendment also reduces the amount
available for the issuance of letters of credit to $25.0 million and amends
certain covenants including, but not limited to, covenants relating to
increasing the minimum mortgaged total value of proved borrowing base properties
from 85% to 90%. Additionally, the Third Amendment provides for new covenants
that, among other things, require us to enter into required swap agreements
representing not less than 65% of our reasonably anticipated projected
production from the proved reserves classified as developed producing reserves
for a period from the Third Amendment effective date through at least December
31, 2022 and prohibit no more than $3 million of our uncontested accounts
payable or accrued expenses, liabilities or other obligations from remaining
outstanding for longer than 90 days. Pursuant to the Third Amendment, the
administrative agent and the lenders consented to a waiver of the Current Ratio
(as defined in the Senior Credit Agreement) for the fiscal quarter ended
September 30, 2020 and suspended testing of the Current Ratio until the fiscal
quarter ending December 31, 2021.
On July 31, 2020 (Successor), we entered into the Waiver which waived
maintenance of the Current Ratio (as defined in the Senior Credit Agreement) of
not less than 1.00 to 1.00 for the fiscal quarter ended June 30, 2020.
On April 30, 2020 (Successor), we entered into the Second Amendment to the
Senior Credit Agreement (Second Amendment) which among other things, (i) reduced
the borrowing base to $200.0 million effective from April 30, 2020, which was
then reduced by $5.0 million monthly starting September 1, 2020 until November
1, 2020, so that the borrowing base was scheduled to be $185.0 million on
November 1, 2020, provided the borrowing base redetermination scheduled for
November 1, 2020 occurred pursuant to the terms of the Senior Credit Agreement,
(ii) increased interest margins to 1.50% to 2.50% for ABR-based loans and 2.50%
to 3.50% for Eurodollar-based loans, (iii) provided that should our Consolidated
Cash Balance (as defined pursuant to the Second Amendment) exceed $10.0 million,
such amounts shall be used to prepay any borrowings under the Senior Credit
Agreement and thereafter, to the extent of any uncollateralized letters of
credit exposure, shall be cash collateralized in accordance with the Senior
Credit Agreement and (iv) allowed for a replacement benchmark rate to the London
Interbank Offered Rate (which may include SOFR, Compounded SOFR or Term SOFR).
The Second Amendment also added provisions related to a loan incurred by us
under the Paycheck Protection Program of the CARES Act. We used, and the Second
Amendment required us to use, the loan proceeds for CARES Forgivable Uses under
the CARES Act. Additionally, the Second Amendment waived, for the fiscal quarter
ended June 30, 2020, that we comply with the requirement under the Senior Credit
Agreement that we unwind certain swap agreements for which settlement payments
were calculated in such fiscal quarter to exceed 100% of actual production.
On November 21, 2019 (Successor), we entered into the First Amendment to the
Senior Credit Agreement which, among other things, (i) reduced the borrowing
base to $240.0 million and (ii) limited the Total Net Indebtedness Leverage
Ratio (as defined in the Senior Credit Agreement) as of the last day of each
fiscal quarter, commencing with the fiscal quarter ending March 31, 2020, of not
greater than 3.50 to 1.00.
As of September 30, 2020 (Successor), after giving effect to the Third
Amendment, we were in compliance with the financial covenants under the Senior
Credit Agreement.
Paycheck Protection Program Loan
On April 16, 2020 (Successor), we entered into the PPP Loan for a principal
amount of approximately $2.2 million from Bank of Montreal under the Paycheck
Protection Program of the CARES Act, which is administered by the U.S. Small
Business Administration. Pursuant to the terms of the CARES Act, the proceeds of
the PPP Loan may be used for payroll costs, mortgage interest, rent or utility
costs. The PPP Loan bears interest at a rate of 1.0% per annum. We are required
to pay principal and interest installments of $0.1 million monthly beginning
November 16, 2020. The maturity date of the PPP Loan is April 16, 2022.
We may elect, at our option, to prepay 20% or less of the borrowings outstanding
under the PPP Loan without premium or penalty, and without notice. Prepayments
of more than 20% of the outstanding borrowings require written advanced notice
and payment of accrued interest. The PPP Loan contains certain events of default
including non-
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payment, breach of representations and warranties, cross-defaults to other loans
with the lender or to material indebtedness, voluntary or involuntary
bankruptcy, judgments and change in control.
Under the terms of the CARES Act, we can apply for and be granted forgiveness
for all or a portion of the PPP Loan. Such forgiveness will be determined,
subject to limitations, based on the use of loan proceeds in accordance with the
terms of the CARES Act during the eight week period after loan origination and
the maintenance or achievement of certain employee levels. We believe we are
eligible for, and are currently pursuing, forgiveness of the PPP Loan in
accordance with the requirements and limitations under the CARES Act; however,
no assurance can be provided that forgiveness of any portion of the PPP Loan
will be obtained.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations
are based upon the unaudited condensed consolidated financial statements, which
have been prepared in accordance with accounting principles generally accepted
in the United States. Preparation of these unaudited condensed consolidated
financial statements requires us to make estimates and judgments that affect the
reported amounts of assets, liabilities, revenues and expenses. There have been
no material changes to our critical accounting policies from those described in
our Annual Report on Form 10-K for the fiscal year ended December 31, 2019
(Successor).
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Results of Operations
Three Months Ended September 30, 2020 (Successor) and 2019 (Predecessor)
We reported a net loss of $153.1 million and $63.3 million for the three months
ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The
table included below sets forth financial information for the periods presented.
Successor Predecessor
Three Months Three Months
Ended Ended
In thousands (except per unit and per Boe amounts) September 30, 2020 September 30, 2019
Net income (loss) $ (153,125) $ (63,284)
Operating revenues:
Oil 33,638 46,275
Natural gas 1,912 301
Natural gas liquids 3,896 3,987
Other 384 246
Operating expenses:
Production:
Lease operating 10,091 11,958
Workover and other 905 1,566
Taxes other than income 2,722 3,012
Gathering and other 13,500 10,147
Restructuring - 3,223
General and administrative:
General and administrative 3,491 21,701
Stock-based compensation 620 (2,278)
Depletion, depreciation and accretion:
Depletion - Full cost 15,326 18,036
Depreciation - Other 283 2,371
Accretion expense 146 105
Full cost ceiling impairment 128,336 45,568
(Gain) loss on sale of Water Assets - (164)
Other income (expenses):
Net gain (loss) on derivative contracts (15,843) 13,457
Interest expense and other (1,692) (10,547)
Reorganization items, net - (1,758)
Production:
Oil - MBbls 877 863
Natural Gas - MMcf 2,266 1,924
Natural gas liquids - MBbls 316 333
Total MBoe(1) 1,571 1,517
Average daily production - Boe/d(1) 17,076 16,489
Average price per unit (2):
Oil price - Bbl $ 38.36 $ 53.62
Natural gas price - Mcf 0.84 0.16
Natural gas liquids price - Bbl 12.33 11.97
Total per Boe(1) 25.11 33.33
Average cost per Boe:
Production:
Lease operating $ 6.42 $ 7.88
Workover and other 0.58 1.03
Taxes other than income 1.73 1.99
Gathering and other 8.59 6.69
Restructuring - 2.12
General and administrative:
General and administrative 2.22 14.31
Stock-based compensation 0.39 (1.50)
Depletion 9.76 11.89
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(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf
to one Bbl of oil. This ratio is based on energy equivalency, not price
equivalency. The price for a barrel of oil equivalent for natural gas is
substantially lower than the price for a barrel of oil.
(2) Amounts exclude the impact of cash paid/received on settled contracts as we
did not elect to apply hedge accounting.
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Oil, natural gas and natural gas liquids revenues were $39.4 million and $50.6
million for the three months ended September 30, 2020 (Successor) and 2019
(Predecessor), respectively. For the three months ended September 30, 2020
(Successor) and 2019 (Predecessor), production averaged 17,076 Boe/d and 16,489
Boe/d, respectively. Average realized prices (excluding the effects of hedging
arrangements) were $25.11 per Boe and $33.33 per Boe for the three months ended
September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The amount
we realize for our production depends predominantly upon commodity prices, which
are affected by changes in market demand and supply, as impacted by overall
economic activity, weather, transportation take-away capacity constraints,
inventory storage levels, quality of production, basis differentials and other
factors.
Lease operating expenses were $10.1 million and $12.0 million for the three
months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. On a per unit basis, lease operating expenses were $6.42 per Boe
and $7.88 per Boe for the three months ended September 30, 2020 (Successor) and
2019 (Predecessor), respectively. The decrease in lease operating expenses in
2020 results from our focus on optimization of production operations and
decreased salt water disposal costs due to lower production volumes and less
produced water.
Workover and other expenses were $0.9 million and $1.6 million for the three
months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. On a per unit basis, workover and other expenses were $0.58 per
Boe and $1.03 per Boe for the three months ended September 30, 2020 (Successor)
and 2019 (Predecessor), respectively. The decreased costs in 2020 relate to
recent strides in improving well and completion designs and fewer workovers
performed.
Taxes other than income were $2.7 million and $3.0 million for the three months
ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. Most
production taxes are based on realized prices at the wellhead. As revenues or
volumes from oil and natural gas sales increase or decrease, production taxes on
these sales also increase or decrease. On a per unit basis, taxes other than
income were $1.73 per Boe and $1.99 per Boe for the three months ended September
30, 2020 (Successor) and 2019 (Predecessor), respectively.
Gathering and other expenses were $13.5 million and $10.1 million for the three
months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. Gathering and other expenses include gathering fees paid to third
parties on our oil and natural gas production, operating expenses of our
gathering support infrastructure, gas treating fees, rig stacking charges and
other. Approximately $3.8 million and $2.5 million for the three months ended
September 30, 2020 (Successor) and 2019 (Predecessor), respectively, relate to
gathering and marketing fees paid to third parties on our oil and natural gas
production. Approximately $9.7 million and $7.3 million for the three months
ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively,
relate to operating expenses on our treating equipment and gathering support
facilities. Our overall production volumes were slightly higher in the current
year period primarily from an increase in our produced natural gas in Monument
Draw. These natural gas volumes are processed through our hydrogen sulfide
treating plant in the area, which led to higher operating expenses, such as
chemical costs, associated with our treating equipment during the current year
period.
Restructuring expense was approximately $3.2 million for the three months ended
2019 (Predecessor). During the three months ended September 30, 2019
(Predecessor), senior executives resigned from their positions. These were
considered terminations without cause under their respective employment
agreements, which entitled them to certain benefits. Additionally, during the
2019 period, we made the decision to consolidate into one corporate office
located in Houston, Texas. The transition includes both severance and relocation
costs as well as incremental costs associated with hiring new employees to
replace key positions.
General and administrative expense was $3.5 million and $21.7 million for the
three months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. The decrease in general and administrative expense primarily
results from a reduction in our payroll and employee-related benefits. Payroll
and employee-related benefits decreased due to a reduction in our workforce
since the prior year period. The decrease in general and administrative costs
also results from other administrative cost reductions as part of our continued
focus on efficiencies and cost savings. On a per unit basis, general and
administrative expenses were $2.22 per Boe and $14.31 per Boe for the three
months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively.
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Stock-based compensation expense was $0.6 million and a credit of $2.3 million
for the three months ended September 30, 2020 (Successor) and 2019
(Predecessor), respectively. Stock-based compensation expense decreased in the
current period due to a reduction in our workforce. During the three months
ended September 30, 2019 (Predecessor), senior executives resigned from their
positions. In accordance with the terms of these senior executives' employment
agreements, unvested stock options and unvested shares of restricted stock were
modified to vest immediately upon termination. For the three months ended
September 30, 2019 (Predecessor), we recognized an incremental reduction to
stock-based compensation expense of $1.1 million associated with these
modifications. Stock-based compensation expense also decreased in the prior year
period due to a reduction in our workforce.
Depletion for oil and natural gas properties is calculated using the unit of
production method, which depletes the capitalized costs of evaluated properties
plus future development costs based on the ratio of production for the current
period to total reserve volumes of evaluated properties as of the beginning of
the period. Depletion expense was $15.3 million and $18.0 million for the three
months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. On a per unit basis, depletion expense was $9.76 per Boe and
$11.89 per Boe for the three months ended September 30, 2020 (Successor) and
2019 (Predecessor), respectively. The lower depletion rate in the Successor
period is attributable to the change in our depletable base as a result of the
adoption of fresh-start accounting and the full cost ceiling test impairment
incurred in the three months ended June 30, 2020.
Under the full cost method of accounting, we are required on a quarterly basis
to determine whether the book value of our oil and natural gas properties
(excluding unevaluated properties) is less than or equal to the "ceiling", based
upon the expected after tax present value (discounted at 10%) of the future net
cash flows from our proved reserves. Any excess of the net book value of our oil
and natural gas properties over the ceiling must be recognized as a non-cash
impairment expense. At September 30, 2020 (Successor), we recorded a full cost
ceiling impairment of $128.3 million. The ceiling test impairment was primarily
driven by a decrease in the first-day-of-the-month average price for crude oil
used in the ceiling test calculation, from $47.37 per barrel at June 30, 2020
(Successor) to $43.63 per barrel at September 30, 2020 (Successor). The ceiling
test impairment also reflects the transfer of $23.6 million of unevaluated
property costs to the full cost pool due to our intent to focus available
capital on Monument Draw. At September 30, 2019 (Predecessor), we recorded a
full cost ceiling impairment of $45.6 million. The ceiling test impairment at
September 30, 2019 (Predecessor) was driven by decreases in
first-day-of-the-month average price for crude oil used in the ceiling test
calculation since June 30, 2019 (Predecessor), when the first-day-of-the-month
average price for crude oil was $61.45 per barrel. Changes in commodity prices,
production rates, levels of reserves, future development costs, transfers of
unevaluated properties, and other factors will determine our actual ceiling test
calculation and impairment analyses in future periods.
On December 20, 2018 (Predecessor), we sold our water infrastructure assets
located in the Delaware Basin for a total adjusted purchase price of $210.9
million. We recognized a cumulative $115.4 million gain on the sale which
includes the $0.2 million increase in the three months ended September 30, 2019
(Predecessor) due to customary post-closing adjustments.
We enter into derivative commodity instruments to economically hedge our
exposure to price fluctuations on our anticipated oil, natural gas and natural
gas liquids production. Consistent with prior years, we have elected not to
designate any positions as cash flow hedges for accounting purposes, and
accordingly, we recorded the net change in the mark-to-market value of these
derivative contracts in the unaudited condensed consolidated statements of
operations. At September 30, 2020 (Successor), we had a $28.7 million derivative
asset, $19.0 million of which was classified as current, and we had a $12.3
million derivative liability, $9.1 million of which was classified as current.
We recorded a net derivative loss of $15.8 million ($21.1 million net unrealized
loss and $5.3 million net realized gain on settled and early terminated
contracts) for the three months ended September 30, 2020 (Successor). During
this period, we terminated certain derivative contracts in advance of their
natural expiration dates and received proceeds of approximately $6.6 million,
which were included in the $5.3 million net realized gains for the period. For
the three months ended September 30, 2019 (Predecessor), we recorded a net
derivative gain of $13.5 million ($11.6 million net unrealized gain and $1.9
million net realized gain on settled and early terminated contracts).
Interest expense and other was $1.7 million and $10.5 million for the three
months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. Interest expense for the Successor period represents interest
associated with borrowings under the Senior Credit Agreement and the PPP Loan.
Interest expense in the Predecessor period
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represents interest associated with the Predecessor Credit Agreement and DIP
Facility. In addition to interest expense, during the three months ended
September 30, 2019 (Predecessor), we paid fees associated with consents and
amendments to our Predecessor Credit Agreement.
We recorded a net loss on reorganization items of $1.8 million for the three
months ended September 30, 2019 (Predecessor) which includes the following:
Predecessor
Three Months
Ended
September 30, 2019
Accrued interest $ 20,274
Write-off debt discount/premium and debt issuance costs (10,953)
Reorganization professional fees and other (11,079)
Gain (loss) on reorganization items $ (1,758)
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Nine Months Ended September 30, 2020 (Successor) and 2019 (Predecessor)
We reported a net loss of $166.0 million and $1.0 billion for the nine months
ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The
table included below sets forth financial information for the periods presented.
Successor Predecessor
Nine Months Nine Months
Ended Ended
In thousands (except per unit and per
Boe amounts) September 30, 2020 September 30, 2019
Net income (loss) $ (165,950) $ (1,040,687)
Operating revenues:
Oil 91,313 145,024
Natural gas 3,102 107
Natural gas liquids 10,086 13,229
Other 1,222 743
Operating expenses:
Production:
Lease operating 32,880 39,617
Workover and other 2,767 5,580
Taxes other than income 7,130 9,213
Gathering and other 39,275 36,057
Restructuring 2,580 15,148
General and administrative:
General and administrative 11,444 44,585
Stock-based compensation 1,793 (8,035)
Depletion, depreciation and accretion:
Depletion - Full cost 46,931 84,579
Depreciation - Other 796 6,026
Accretion expense 440 307
Full cost ceiling impairment 188,443 985,190
(Gain) loss on sale of Water Assets - 3,618
Other income (expenses):
Net gain (loss) on derivative contracts 67,695 (34,332)
Interest expense and other (4,889) (37,606)
Reorganization items, net - (1,758)
Income tax benefit (provision) - 95,791
Production:
Oil - MBbls 2,589 2,723
Natural Gas - MMcf 6,437 6,381
Natural gas liquids - MBbls 917 911
Total MBoe(1) 4,579 4,698
Average daily production - Boe(1) 16,712 17,209
Average price per unit (2):
Oil price - Bbl $ 35.27 $ 53.26
Natural gas price - Mcf 0.48 0.02
Natural gas liquids price - Bbl 11.00 14.52
Total per Boe(1) 22.82 33.71
Average cost per Boe:
Production:
Lease operating $ 7.18 $ 8.43
Workover and other 0.60 1.19
Taxes other than income 1.56 1.96
Gathering and other 8.58 7.67
Restructuring 0.56 3.22
General and administrative:
General and administrative 2.50 9.49
Stock-based compensation 0.39 (1.71)
Depletion 10.25 18.00
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(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf
to one Bbl of oil. This ratio is based on energy equivalency, not price
equivalency. The price for a barrel of oil equivalent for natural gas is
substantially lower than the price for a barrel of oil.
(2) Amounts exclude the impact of cash paid/received on settled contracts as we
did not elect to apply hedge accounting.
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Oil, natural gas and natural gas liquids revenues were $104.5 million and $158.4
million for the nine months ended September 30, 2020 (Successor) and 2019
(Predecessor), respectively. For the nine months ended September 30, 2020
(Successor) and 2019 (Predecessor), production averaged 16,712 Boe/d and 17,209
Boe/d, respectively. Our average daily oil, natural gas and natural gas liquids
production decreased in the nine months ended September 30, 2020 (Successor)
when compared to the same period in the prior year primarily due to our
temporary shut-in of a portion of producing wells across all our operating areas
during the months of May and June 2020. Estimated downtime associated with these
temporary shut-ins was approximately 1,800 Boe/d for the nine months ended
September 30, 2020 (Successor). The production decline caused by temporary
shut-ins in the current year period was partially offset by new wells put online
since the prior year period. Average realized prices (excluding the effects of
hedging arrangements) were $22.82 per Boe and $33.71 per Boe for the nine months
ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The
amount we realize for our production depends predominantly upon commodity
prices, which are affected by changes in market demand and supply, as impacted
by overall economic activity, weather, transportation take-away capacity
constraints, inventory storage levels, quality of production, basis
differentials and other factors.
Lease operating expenses were $32.9 million and $39.6 million for the nine
months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. On a per unit basis, lease operating expenses were $7.18 per Boe
and $8.43 per Boe for the nine months ended September 30, 2020 (Successor) and
2019 (Predecessor), respectively. The decrease in lease operating expenses in
2020 results from our focus on optimization of production operations and
decreased salt water disposal costs due to lower production volumes and less
produced water.
Workover and other expenses were $2.8 million and $5.6 million for the nine
months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. On a per unit basis, workover and other expenses were $0.60 per
Boe and $1.19 per Boe for the nine months ended September 30, 2020 (Successor)
and 2019 (Predecessor), respectively. The decreased costs in 2020 relate to
recent strides in improving well and completion designs and fewer workovers
performed.
Taxes other than income were $7.1 million and $9.2 million for the nine months
ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. Most
production taxes are based on realized prices at the wellhead. As revenues or
volumes from oil and natural gas sales increase or decrease, production taxes on
these sales also increase or decrease. On a per unit basis, taxes other than
income were $1.56 per Boe and $1.96 per Boe for the nine months ended September
30, 2020 (Successor) and 2019 (Predecessor), respectively.
Gathering and other expenses were $39.3 million and $36.1 million for the nine
months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. Gathering and other expenses include gathering fees paid to third
parties on our oil and natural gas production, operating expenses of our
gathering support infrastructure, gas treating fees, rig stacking charges and
other. Approximately $9.0 million and $9.6 million for the nine months ended
September 30, 2020 (Successor) and 2019 (Predecessor), respectively, relate to
gathering and marketing fees paid to third parties on our oil and natural gas
production. Oil and natural gas production volumes were lower in the current
period due to the temporary shut-in of a portion of producing wells during the
months of May and June 2020. Approximately $26.9 million and $24.8 million for
the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively, relate to operating expenses on our treating equipment and
gathering support facilities. In April 2019 (Predecessor), we installed a
hydrogen sulfide treating plant that more efficiently removes hydrogen sulfide
from our produced natural gas and reduces our reliance on expensive
wellhead-level treating. Until the treating plant was operational, we incurred
$10.9 million of wellhead-level costs to remove hydrogen sulfide from natural
gas produced from our Monument Draw properties during the nine months ended
September 30, 2019 (Predecessor). Our produced natural gas from the Monument
Draw area increased in the current year period, despite a decrease in our
overall production volumes. These natural gas volumes are processed through our
hydrogen sulfide treating plant in the area, which led to higher operating
expenses, such as chemical costs, associated with our treating equipment during
the current year period. Also included are $3.4 million and $0.8 million of rig
stacking charges for the nine months ended September 30, 2020 (Successor) and
2019 (Predecessor).
Restructuring expense was approximately $2.6 million and $15.1 million for the
nine months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. During the nine months ended September 30, 2020 (Successor), we
incurred restructuring charges related to the consolidation into one corporate
office and had reductions in our
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workforce due to efforts to improve efficiencies and go forward costs. In May
2020 (Successor), in furtherance of the consolidation into one corporate office,
we exercised a one-time early termination option under the lease agreement for
our office space in Denver, Colorado. During the nine months ended September 30,
2019 (Predecessor), several senior executives resigned from their positions.
These were considered terminations without cause under their respective
employment agreements, which entitled them to certain benefits. Additionally,
during the 2019 period, we made the decision to consolidate into one corporate
office located in Houston, Texas. The transition includes both severance and
relocation costs as well as incremental costs associated with hiring new
employees to replace key positions.
General and administrative expense was $11.4 million and $44.6 million for the
nine months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. The decrease in general and administrative expense primarily
results from a reduction in our payroll and employee-related benefits. Payroll
and employee-related benefits decreased due to a reduction in our workforce
since the prior year period. The decrease in general and administrative costs
also results from other administrative cost reductions as part of our continued
focus on efficiencies and cost savings. On a per unit basis, general and
administrative expenses were $2.50 per Boe and $9.49 per Boe for the nine months
ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.
Stock-based compensation expense was $1.8 million and a credit of $8.0 million
for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. During the nine months ended September 30, 2019 (Predecessor),
several senior executives resigned from their positions. In accordance with the
terms of these senior executives' employment agreements, unvested stock options
and unvested shares of restricted stock were modified to vest immediately upon
terminations. For the nine months ended September 30, 2019 (Predecessor), we
recognized an incremental reduction to stock-based compensation expense of $9.5
million associated with these modifications. Stock-based compensation expense
also decreased in the current period due to a reduction in our workforce.
Depletion for oil and natural gas properties is calculated using the unit of
production method, which depletes the capitalized costs of evaluated properties
plus future development costs based on the ratio of production for the current
period to total reserve volumes of evaluated properties as of the beginning of
the period. Depletion expense was $46.9 million and $84.6 million for the nine
months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. On a per unit basis, depletion expense was $10.25 per Boe and
$18.00 per Boe for the nine months ended September 30, 2020 (Successor) and 2019
(Predecessor), respectively. The lower depletion rate in the Successor period is
attributable to the change in our depletable base as a result of the adoption of
fresh-start accounting and the full cost ceiling test impairment incurred in the
three months ended June 30, 2020.
Under the full cost method of accounting, we are required on a quarterly basis
to determine whether the book value of our oil and natural gas properties
(excluding unevaluated properties) is less than or equal to the "ceiling", based
upon the expected after tax present value (discounted at 10%) of the future net
cash flows from our proved reserves. Any excess of the net book value of our oil
and natural gas properties over the ceiling must be recognized as a non-cash
impairment expense. At September 30, 2020 (Successor), we recorded a full cost
ceiling impairment of $128.3 million. The ceiling test impairment was primarily
driven by a decrease in the first-day-of-the-month average price for crude oil
used in the ceiling test calculation, from $47.37 per barrel at June 30, 2020
(Successor) to $43.63 per barrel at September 30, 2020 (Successor). The ceiling
test impairment also reflects the transfer of $23.6 million of unevaluated
property costs to the full cost pool due to our intent to focus available
capital on Monument Draw. At June 30, 2020 (Successor), we recorded a full cost
ceiling impairment of $60.1 million. The ceiling test impairment was primarily
driven by a decrease in the first-day-of-the-month average price for crude oil
used in the ceiling test calculation, from $55.96 per barrel at March 31, 2020
(Successor) to $47.37 per barrel at June 30, 2020 (Successor). This average
price decline was partially offset by favorable differentials and lower
operating expenses. We recorded a full cost ceiling test impairment charge of
$985.2 million for the nine months ended September 30, 2019 (Predecessor). The
ceiling test impairment at September 30, 2019 (Predecessor) was driven by
decreases in the first-day-of-the-month average price for crude oil used in the
ceiling test calculation since June 30, 2019 (Predecessor), when the
first-day-of-month average price for crude oil was $61.45 per barrel. At
June 30, 2019 (Predecessor), we recorded a full cost ceiling impairment of
$664.4 million. The ceiling test impairment at June 30, 2019 (Predecessor) was
primarily driven by our continued focus on Monument Draw. Accordingly, we
transferred approximately $481.7 million of unevaluated property costs to the
full cost pool as of June 30, 2019 (Predecessor), the majority of which was
associated with our Hackberry Draw area. At March 31, 2019 (Predecessor), we
recorded a full cost ceiling impairment of $275.2 million. The ceiling test
impairment at March 31, 2019 (Predecessor) was driven by a decrease in the
first-day-of-the-month average price for crude oil used in the ceiling
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test calculation and our intent to expend capital only on our most economic
areas. As such, we identified certain leases in the Hackberry Draw area with
near-term expirations and transferred approximately $51.0 million of associated
unevaluated property costs to the full cost pool during the three months ended
March 31, 2019 (Predecessor). Changes in commodity prices, production rates,
levels of reserves, future development costs, transfers of unevaluated
properties, and other factors will determine our actual ceiling test calculation
and impairment analyses in future periods.
On December 20, 2018 (Predecessor), we sold our water infrastructure assets
located in the Delaware Basin for a total adjusted purchase price of $210.9
million. We recognized a cumulative $115.9 million gain on the sale. The gain
was reduced during the nine months ended September 30, 2019 by approximately
$3.6 million as a result of customary post-closing adjustments.
We enter into derivative commodity instruments to economically hedge our
exposure to price fluctuations on our anticipated oil, natural gas and natural
gas liquids production. Consistent with prior years, we have elected not to
designate any positions as cash flow hedges for accounting purposes, and
accordingly, we recorded the net change in the mark-to-market value of these
derivative contracts in the unaudited condensed consolidated statements of
operations. At September 30, 2020 (Successor), we had a $28.7 million derivative
asset, $19.0 million of which was classified as current, and we had a $12.3
million derivative liability, $9.1 million of which was classified as current.
We recorded a net derivative gain of $67.7 million ($24.0 million net unrealized
gain and $43.7 million net realized gain on settled and early terminated
contracts) for the nine months ended September 30, 2020 (Successor). During the
nine months ended September 30, 2020 (Successor), we terminated certain
derivative contracts in advance of their natural expiration dates and received
net proceeds of approximately $22.9 million, which were included in the $43.7
million net realized gain for the period. For the nine months ended September
30, 2019 (Predecessor), we recorded a net derivative loss of $34.3 million
($45.8 million net unrealized loss and $11.5 million net realized gain on
settled and early terminated contracts).
Interest expense and other was $4.9 million and $37.6 million for the nine
months ended September 30, 2020 (Successor) and 2019 (Predecessor),
respectively. Interest expense for the Successor period represents interest
associated with borrowings under the Senior Credit Agreement and the PPP loan.
Interest expense in the Predecessor period represents interest associated with
the Predecessor Credit Agreement, the DIP Facility and the 6.75% senior notes.
In addition to interest expense, during the nine months ended September 30, 2019
(Predecessor), we paid fees associated with consents and amendments to our
Predecessor Credit Agreement.
We recorded a net loss on reorganization items of $1.8 million for the nine
months ended September 30, 2019 (Predecessor) which includes the following:
Predecessor
Nine Months
Ended
September 30, 2019
Accrued interest $ 20,274
Write-off debt discount/premium and debt issuance costs (10,953)
Reorganization professional fees and other (11,079)
Gain (loss) on reorganization items $ (1,758)
We recorded an income tax benefit of $95.8 million for the nine months ended
September 30, 2019 (Predecessor), resulting from the reduction to the deferred
tax liability generated by the impact of the ceiling test impairment on oil and
gas properties and the deferred tax asset created by the tax loss from
operations. The 8.4% effective tax rate for the nine months ended September 30,
2019 (Predecessor) differs from the 21% statutory rate because of non-deductible
executive compensation and non-deductible realized built in losses, and
valuation allowances on deferred tax assets.
Recently Issued Accounting Pronouncements
We discuss recently adopted and issued accounting standards in Item1. Condensed
Consolidated Financial Statements (Unaudited)-Note 1, "Financial Statement
Presentation."
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