LONESTAR RESOURCES U

The following discussion and analysis should be read in conjunction with our
Unaudited Condensed Consolidated Financial Statements and Notes thereto included
herein and our Consolidated Financial Statements and Notes thereto included in
our Annual Report on Form 10-K for the year ended December 31, 2019 (the "Form
10-K"), along with Management's Discussion and Analysis of Financial Condition
and Results of Operations contained in the Form 10-K. Any terms used but not
defined herein have the same meaning given to them in the Form 10-K. Our
discussion and analysis includes forward-looking information that involves risks
and uncertainties and should be read in conjunction with Risk Factors under Item
1A of the Form 10-K, along with Forward Looking Information at the end of this
section for information on the risks and uncertainties that could cause our
actual results to be materially different than our forward-looking statements.
OVERVIEW
Lonestar is an independent oil and natural gas company focused on the
exploration, development and production of unconventional oil, natural gas
liquids and natural gas in the Eagle Ford Shale play in South Texas.
Market Developments and Response to Commodity Price Declines
The COVID-19 coronavirus ("COVID-19") pandemic has resulted in a severe
worldwide economic downturn, significantly disrupting the demand for oil
throughout the world, and has created significant volatility, uncertainty and
turmoil in the oil and gas industry. The decrease in demand for oil combined
with the oil supply increase attributable to the battle for market share among
the Organization of the Petroleum Exporting Countries ("OPEC"), Russia and other
oil producing nations, resulted in oil prices declining significantly beginning
in late February 2020. During this time NYMEX oil prices declined from averages
in the mid-$50s per Bbl range in January and February 2020, to an average of
approximately $30 per Bbl in March. NYMEX oil prices continued to decline in
April 2020 to an average of $17 per Bbl in response to uncertainty about the
duration of the COVID-19 pandemic and storage constraints resulting from
over-supply of produced oil, before recovering to the lower $40s per Bbl by late
July after the implementation of production cuts by OPEC, significant production
cuts by domestic operators, and an easement of storage capacity concerns. As of
mid-November 2020, oil prices remained in the mid-$40s per Bbl due to continued
downward pressure on demand because of COVID-19.
The length of this demand disruption is unknown, and there is significant
uncertainty regarding the long-term impact to global oil demand, which will
ultimately depend on various factors and consequences beyond our control, such
as the duration and scope of the pandemic, the length and severity of the
worldwide economic downturn, additional actions by businesses and governments in
response to both the pandemic and the decrease in oil prices, the speed and
effectiveness of responses to combat the virus, and the time necessary to
equalize oil supply and demand to restore oil pricing.

In response to these developments, we have implemented the following operational
and financial measures:

1.Reduced budgeted 2020 capital spending from $80-$85 million to approximately
$65 million, almost all of which had been incurred by the end of June 2020;
2.Deferred the remainder of our 2020 drilling program through the end of the
year;
3.Implemented cost-reduction measures including negotiating reduced rates for
water disposal, chemicals, rentals, and workovers;
4.Shut in or stored approximately 4,700 BOE per day of production during
late-April and all of May 2020, primarily at our oil-rich fields in our Central
Eagle Ford Area; and
5.Entered into new natural gas swaps in October 2020 for January 2021 through
December 2021, which hedge 10,000 MMBtu per day at an average price of $3.04 per
MMBtu, and also entered into natural gas swaps for January 2022 through December
2022, which hedge 5,000 MMBtu per day at an average price of $2.70 per MMBtu. In
November 2020, we entered into new crude oil swaps for December 2020, which
hedge 4,000 barrels per day at an average price of $41.08 per barrel. We also
entered into new crude oil swaps for January 2021 through December 2021, which
hedge 1,000 barrels per day at an average price of $42.20 per barrel. Prior to
commencement of the Chapter 11 Cases (see below), we terminated and monetized
our existing hedge portfolio in September 2020.
We continue to assess the global impacts of the COVID-19 pandemic and expect to
continue to modify our plans as more clarity around the full economic impact of
COVID-19 becomes available. See Risk Factors for further discussion of the
adverse impacts of the COVID-19 pandemic on our business.

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Chapter 11 Cases

On September 30, 2020, the Company and certain of its direct and indirect
wholly-owned subsidiaries (collectively with the Company, the "Debtors")
commenced voluntary cases (the "Chapter 11 Cases") under chapter 11 of title 11
of the United States Code (the "Bankruptcy Code") in the United States
Bankruptcy Court for the Southern District of Texas (the "Bankruptcy Court").
Prior to this, on September 14, 2020, we entered into a restructuring support
agreement (the "RSA") with certain holders of our 11.25% Senior Notes (defined
below) and certain lenders of our Credit Facility (defined below) and Citibank,
N.A., as agent, to support a restructuring in accordance with the terms set
forth therein. On September 30, 2020, the Debtors also filed with the Bankruptcy
Court a prepackaged chapter 11 plan of reorganization (the "Restructuring
Plan"), as contemplated by the RSA, to restructure the Debtors. We expect to
continue operations in the normal course for the duration of the Chapter 11
Cases. To ensure ordinary course operations, we have obtained approval from the
Bankruptcy Court for certain "first day" motions, including motions to obtain
customary relief intended to assure our ability to continue our ordinary course
operations after the filing date. For more information on the Chapter 11 Cases
and related matters, please see Note 1. Basis of Presentation in Part I, Item 1.
Financial Information of this Quarterly Report. The Bankruptcy Court confirmed
our Restructuring Plan on November 12, 2020.

NASDAQ Delisting

Our common stock was traded on the NASDAQ Global Select Market (the "NASDAQ")
under the symbol "LONE" until October 12, 2020. On October 1, 2020, we received
a letter from the NASDAQ notifying us that, as a result of the Chapter 11 Cases
and in accordance with NASDAQ rules, our securities would be delisted at the
opening of business on October 12, 2020. On October 12, 2020, our common stock
commenced trading on the OTC Bulletin Board or "pink sheets" under the symbol
"LONEQ". NASDAQ filed a Form 25 on October 27, 2020 to delist our common stock
which went into effect ten days after it was filed.

Operational Highlights for the Third Quarter of 2020
During the third quarter of 2020, we achieved the following operating and
financial results:
•Production decreased by 20% compared to the third quarter of 2019, averaging
14,419 BOE per day versus 18,097 BOE per day. Compared to the second quarter of
2020, production increased 8%, or 1,080 BOE per day, from 13,339 BOE per day. In
response to the collapse in commodity prices, we shut in or stored approximately
4,700 BOE per day of production during late-April and all of May 2020, primarily
in our Central Eagle Ford Area. These shut-in wells came back online during the
first week of June, and are a significant reason for the quarter-to-quarter
increase in production, along with new production coming online from three
Hawkeye wells in the Gonzales County AMI (see below) at the end of June.
•Drilled and completed three new wells and drilled three additional uncompleted
wells ("DUCs") at our Hawkeye wells (see below) in July.
•Continued to lower our operating expenses on a per-BOE basis. Compared to the
third quarter of 2019, lease operating and gas gathering costs decreased on a
per-BOE basis due to our continued focus on controlling expenses. However,
general and administrative expenses increased significantly during the current
quarter due to professional fees related to preparation for the Chapter 11
Cases.
Changes in operating results between the third quarters of 2020 and 2019 were
primarily driven by the following:
•Revenues decreased sharply by $21.0 million, or 40%, between the two quarters,
primarily driven by a 20% decrease in commodity prices and a 20% decrease in
production.
•G&A increased significantly by $11.7 million, or 283%, between the two
quarters, primarily due to incremental professional costs incurred related to
our restructuring, which individually totaled $12.4 million for the quarter.
•Compared to the third quarter of 2019, lease operating and gas gathering
expense decreased by 17% to $5.02 per BOE, production and ad valorem taxes
decreased by 17% to $1.50 per BOE, general and administrative expense increased
by 381% to $11.92 per BOE, and interest expense increased $1.81 per BOE.
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•Derivative financial instruments had a net loss of $9.7 million in the third
quarter of 2020, compared to a net gain of $21.5 million in the third quarter of
2019. As noted below, prior to commencement of the Chapter 11 Cases, we
terminated and monetized our outstanding hedge portfolio on September 10, 2020,
which resulted in a net realized gain of approximately $30.5 million (comprised
of $39.9 million for oil swaps, offset by negative $6.7 million for natural gas
swaps and negative $2.7 million for interest rate swaps). Of the $30.5 million
net gain, $4.2 million was associated with hedges which would have settled
during the remainder of the third quarter of 2020 while the remaining $26.3
million was related to settlement periods after the current quarter.
During the third quarter of 2020, we recognized net loss attributable to common
stockholders of $38.5 million, or $1.52 per diluted common share, compared to
net income attributable to common stockholders of $14.1 million, or $0.33 per
diluted common share, in the third quarter of 2019. We generated $82.7 million
of cash flow from operating activities during the first nine months of 2020,
which was $29.8 million more than the $52.9 million generated by operating
activities during the first nine months of 2019.
Gonzales County AMI
In February 2020, we entered into a Joint Development Agreement (the "JDA") in
Gonzales County with one of the largest producers in the Eagle Ford which
encompass an Area of Mutual Interest (the "AMI") totaling approximately 15,000
acres.
The agreement calls for Lonestar to operate a minimum of three to four Eagle
Ford Shale wells annually on behalf of the two companies through 2022 that are
intended to hold-by-production approximately 6,000 gross acres within the AMI.
The agreement gives Lonestar's partner the option to participate in each well
with a 50% working interest or to participate via a carried working interest
that ranges from approximately 9 to 17%, depending on location.
In June, we began flowback operations on the Hawkeye #14H, Hawkeye #15H, and
Hawkeye #16H. These recorded maximum rates over a 30-day period ("Max-30 rates")
of 1,461 BOE per day, 86% of which was crude oil. Through the first 120 days of
production, these wells have produced an average of 111,000 Bbls.
•Hawkeye #14H - With a 10,979' perforated interval, the #14H recorded Max-30
rates of 1,186 Bbls per day of oil, 87 Bbls per day of NGLs, and 625 Mcf per day
of natural gas, or 1,377 BOE per day on a three-stream basis and was achieved on
a 30/64" choke. The #14H well has been on-stream for more than four months now,
and had 120-day rates have averaged 868 Bbls per day of oil, 49 Bbls per day of
NGLs, and 353 Mcf per day of natural gas, or 976 BOE per day on a three-stream
basis.
•Hawkeye #15H - With a 10,608' perforated interval, the #14H recorded Max-30
rates of 1,372 Bbls per day of oil, 101 Bbls per day of NGLs, and 729 Mcf per
day of natural gas, or 1,595 BOE per day on a three-stream basis and was
achieved on a 30/64" choke. The #15H has been on-stream for more than four
months now, and had 120-day rates of 970 Bbls per day of oil, 55 Bbls per day of
NGLs, and 394 Mcf per day of natural gas, or 1,090 BOE per day on a three-stream
basis and was achieved on a 30/64" choke.
•Hawkeye #16H - With a 9,885' perforated interval, the #16H recorded Max-30
rates of 1,217 Bbls per day of oil, 88 Bbls per day of NGLs, and 635 Mcf per day
of natural gas, or 1,411 BOE per day on a three-stream basis and was achieved on
a 30/64" choke. The #16H has been on-stream for more than four months now, and
had 120-day rates of 958 Bbls per day of oil, 53 Bbls per day of NGLs, and 381
Mcf per day of natural gas, or 1,074 BOE per day on a three-stream basis and was
achieved on a 30/64" choke.
We hold a 50% working interest and 38% net revenue interest in these wells.
In July, we completed drilling operations on the Hawkeye #33H, Hawkeye #34H, and
Hawkeye #35. These wells were drilled to total-measured depths of 20,500 feet,
20,358 feet and 20,467 feet, respectively, and are expected to have perforated
intervals averaging approximately 10,800 feet. These wells are currently held in
inventory as Drilled Uncompleted ("DUC's"). We expect to hold a 50% working
interest and 37.5% net revenue interest in these wells.


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RESULTS OF OPERATIONS
Certain of our operating results and statistics for the three and nine months
ended September 30, 2020 and 2019 are summarized below:
Three Months Ended

September 30, Nine Months Ended September 30,
In thousands, except per share and unit data

2020 2019 2020 2019
Operating Results
Net loss attributable to common stockholders $ (38,473) $ 14,058 $ (194,423) $ (35,394)
Net loss per common share - basic(1) (1.52) 0.34 (7.70) (1.42)
Net loss per common share - diluted(1) (1.52) 0.33 (7.70) (1.42)
Net cash provided by operating activities 52,320 14,686 82,731 52,873
Revenues
Oil $ 24,524 $ 42,187 $ 66,510 $ 120,496
NGLs 3,202 3,439 7,565 10,381
Natural gas 4,383 7,519 12,285 15,224
Total revenues $ 32,109 $ 53,145 $ 86,360 $ 146,101
Total production volumes by product
Oil (Bbls) 661,465 725,405 1,899,145 2,024,862
NGLs (Bbls) 305,920 387,256 876,853 868,811
Natural gas (Mcf) 2,154,969 3,313,757 6,468,594 6,210,617
Total barrels of oil equivalent (6:1) 1,326,547 1,664,954 3,854,097 3,928,776
Daily production volumes by product
Oil (Bbls/d) 7,190 7,885 6,931 7,417
NGLs (Bbls/d) 3,325 4,209 3,200 3,182
Natural gas (Mcf/d) 23,424 36,019 23,608 22,750
Total barrels of oil equivalent (BOE/d) 14,419 18,097 14,066 14,391
Average realized prices
Oil ($ per Bbl) $ 37.08 $ 58.16 $ 35.02 $ 59.51
NGLs ($ per Bbl) 10.47 8.88 8.63 11.95
Natural gas ($ per Mcf) 2.03 2.27 1.90 2.45
Total oil equivalent, excluding the effect
from commodity derivatives ($ per BOE) 24.20 31.92 22.41 37.19
Oil equivalent price impact of settled
hedges ($ per BOE) 33.23 (0.33) 19.04 (1.41)
Total oil equivalent, including the effect
from commodity derivatives ($ per BOE) 57.43 31.59 41.45 35.78
Operating and other expenses
Lease operating $ 4,763 $ 8,948 $ 16,430 $ 23,472
Gas gathering, processing and transportation 1,891 1,107 4,916 3,223
Production and ad valorem taxes 1,994 3,017 6,084 8,126
Depreciation, depletion and amortization 18,256 24,635 59,184 64,120
General and administrative 15,808 4,124 24,664 12,345
Interest expense 11,399 11,295 33,521 32,730
Operating and other expenses per BOE
Lease operating $ 3.59 $ 5.37 $ 4.26 $ 5.97
Gas gathering, processing and transportation 1.43 0.66 1.28 0.82
Production and ad valorem taxes 1.50 1.81 1.58 2.07
Depreciation, depletion and amortization 13.76 14.80 15.36 16.32
General and administrative 11.92 2.48 6.40 3.14
Interest expense 8.59 6.78 8.70 8.33



(1) Basic and diluted earnings per share are calculated using the two-class
method. See Note 1. Basis of Presentation in the Notes to Unaudited Condensed
Consolidated Financial Statements included in Item 1.

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Production

The table below summarizes our production volumes for the three and nine months
ended September 30, 2020 and 2019:

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 Change 2020 2019 Change
Oil (Bbls/d) 7,190 7,885 (9) % 6,931 7,417 (7) %
NGLs (Bbls/d) 3,325 4,209 (21) % 3,200 3,182 1 %
Natural gas (Mcf/d) 23,424 36,019 (35) % 23,608 22,750 4 %
Total (BOE/d) 14,419 18,097 (20) % 14,066 14,391 (2) %


Total production during the third quarter of 2020 averaged 14,419 BOE per day, a
decrease of 20%, or 3,678 BOE per day, compared to the same period in 2019. The
Company has not brought any additional wells online since the Hawkeye #14, #15
and #16 started producing at the end of the second quarter. This lack of
additional production coming on-line from new completions, as well as an overall
decline in production due to the Company's reduced drilling schedule through the
first half of 2020, contributed to the decline between the two quarters.
Total production during the first nine months of 2020 averaged 14,066 BOE per
day, a decrease of 2%, or 325 BOE per day, compared to the same period in 2019.
Higher relative production during the first quarter of 2020 resulting from the
Company's two-rig drilling program through the end of 2019 was largely offset by
the declines noted above for the third quarter, as well as the effects of
production shut-in during the second quarter of 2020 due to low commodity
prices.
Our production during the third quarter of 2020 was 73% oil and NGLs, compared
to 70% during the third quarter of 2019.
Oil, Natural Gas Liquid and Natural Gas Revenues
The table below summarizes our production revenues for the three and nine months
ended September 30, 2020 and 2019:
Three Months Ended September 30, Nine Months Ended September 30,
In thousands 2020 2019 Change 2020 2019 Change
Oil $ 24,524 $ 42,187 (42) % $ 66,510 $ 120,496 (45) %
NGLs 3,202 3,439 (7) % 7,565 10,381 (27) %
Natural gas 4,383 7,519 (42) % 12,285 15,224 (19) %
Total revenues $ 32,109 $ 53,145 (40) % $ 86,360 $ 146,101 (41) %


Our oil, NGL and natural gas revenues during the three months ended September
30, 2020 decreased $21.0 million, or 40%, compared to those revenues for the
same period in 2019. For the nine months ended September 30, 2020, our oil, NGL
and natural gas revenues decreased $59.7 million, or 41%, compared to the same
period in 2019. The changes in our oil, NGL and natural gas revenues are due to
changes in production quantities and commodity prices (excluding any impact of
our commodity derivative contracts), as reflected in the following table:
Three Months Ended September 30, 2020 vs Nine Months Ended September 30, 2020 vs
2019 2019
Decrease in Percentage Decrease Decrease in Percentage Decrease
In thousands Revenues in Revenues Revenues in Revenues
Change in oil, NGL and natural gas
revenues due to:
Decrease in production $ (10,802) (20) % $ (2,777) (2) %
Decrease in commodity prices (10,234) (20) % (56,964) (39) %
Total change in oil, NGL and natural gas
revenues $ (21,036) (40) % $ (59,741) (41) %


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Excluding the impact of our commodity derivative contracts, our net realized
commodity prices and NYMEX differentials were as follows during the three and
nine months ended September 30, 2020 and 2019:
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 Change 2020 2019 Change
Average net realized price
Oil ($/Bbl) $ 37.08 $ 58.16 (36) % $ 35.02 $ 59.51 (41) %
NGLs ($/Bbls) 10.47 8.88 18 % 8.63 11.95 (28) %
Natural gas ($/Mcf) 2.03 2.27 (10) % 1.90 2.45 (23) %
Total ($/BOE) 24.20 31.92 (24) % 22.41 37.19 (40) %
Average NYMEX differentials
Oil per Bbl $ (3.86) $ 1.71 (326) % $ (3.31) $ 2.69 (223) %
Natural gas per Mcf 0.03 (0.11) (127) % 0.03 (0.16) (119) %


The average wellhead price for our production in the three months ended
September 30, 2020 was $24.20 per BOE, a 24% decrease compared to the average
price for the comparable period in 2019. The realized wellhead price for the
nine months ended September 30, 2020 was $22.41 per BOE, a 40% decrease compared
to the average price of the comparable period in 2019. Reported wellhead
realizations were driven lower by a decrease in the crude oil and natural gas
benchmark prices between the periods, in addition to a significantly lower NYMEX
oil differential. Our realized NGL price was $10.47 per Bbl and $8.63 per Bbl,
or 26% and 23% of NYMEX WTI, respectively, for the three and nine months ended
September 30, 2019, respectively.
Our average NYMEX oil differential decreased quarter over quarter by $5.57 per
Bbl and $6.00 per Bbl when comparing the year-to-date periods. Differentials
were impacted significantly during the current year as a result of the April
2020 price collapse that saw WTI drop to approximately negative $40 per Bbl at
one point. This led to temporary storage restraints at purchasers which caused
marketing rates to increase as high as $10 per Bbl. The drastic change in price
also created sharp, yet temporary, changes in oil related differentials that
fell to approximately negative $8 per Bbl in May 2020. Although WTI prices
recovered to the mid-$40s as of September 30, 2019, they are still significantly
below where they were a year ago.
Our natural gas NYMEX differentials are generally caused by movement in the
NYMEX natural gas prices during the month, as most of our natural gas is sold on
an index price that is set near the first of each month. While the percentage
change in NYMEX natural gas differentials can be large, these differentials are
seldom more than a dollar above or below NYMEX price.
Commodity Derivative Contracts
We utilize oil and natural gas derivative contracts to provide an economic hedge
of our exposure to commodity price risk associated with anticipated future
production and to provide more certainty to our future cash flows. These
contracts have historically consisted of fixed-price swaps, collars and basis
swaps.
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The following table summarizes the net cash receipts (payments) on the Company's
commodity derivatives and the relative price impact (per Bbl or Mcf) for the
three and nine months ended September 30, 2020 and 2019:
Three Months Ended June 30,

Nine Months Ended September 30,

2020 2019 2020 2019
In thousands, except price Net realized Net realized Net realized Net realized
impact settlements Price impact settlements Price impact settlements Price impact settlements Price impact
Receipts (payments) on
settlements of oil derivatives $ 51,319 $ 77.58 $ (1,022) $ (1.41) $ 72,580 $ 38.22 $ (5,627) $ (2.78)
(Payments) receipts on
settlements of natural gas
derivatives (5,644) (2.62) 178 0.05 (3,189) (0.49) 1,769 0.28
Total net commodity derivative
settlements $ 45,675 $ (844) $ 69,391 $ (3,858)


Our realized net gain on commodity derivative contracts was $44.0 million and
$73.3 million for the three and nine months ended September 30, 2020. Included
in those amounts is $33.2 million, net ($39.9 million in oil hedges and negative
$6.7 million in natural gas hedges, gross), which was realized upon termination
of our hedging portfolio in September 2020 prior to the commencement of the
Chapter 11 Cases We realized an average gain of $33.23 and $19.04 per BOE on our
oil and natural gas swaps during the three and nine months ended September 30,
2020, respectively, as compared to an average loss of $0.33 and $1.41 per BOE
for the three and nine months ended September 30, 2019.
Subsequent to filing the Restructuring Plan, the Company entered into new
natural gas swaps in October 2020 for January 2021 through December 2021, which
hedge 10,000 MMBtu per day at an average price of $3.04 per MMBtu, and also
entered into natural gas swaps for January 2022 through December 2022, which
hedge 5,000 MMBtu per day at an average price of $2.70 per MMBtu. In November
2020, we entered into new crude oil swaps for December 2020, which hedge 4,000
barrels per day at an average price of $41.08 per barrel. We also entered into
new crude oil swaps for January 2021 through December 2021, which hedge 1,000
barrels per day at an average price of $42.20 per barrel. We will continue to
rebuild its hedge portfolio going forward as economic conditions warrant.
Production Expenses
The table below presents detail of production expenses for the three and nine
months ended September 30, 2020 and 2019:
In thousands, except expense per Three Months Ended September 30, Nine Months Ended September 30,
BOE 2020 2019 Change 2020 2019 Change
Production expenses
Lease operating $ 4,763 $ 8,948 (47) % $ 16,430 $ 23,472 (30) %
Gas gathering, processing and
transportation 1,891 1,107 71 % 4,916 3,223 53 %
Production and ad valorem taxes 1,994 3,017 (34) % 6,084 8,126 (25) %
Depreciation, depletion and
amortization 18,256 24,635 (26) % 59,184 64,120 (8) %
Production expenses per BOE
Lease operating $ 3.59 $ 5.37 (33) % $ 4.26 $ 5.97 (29) %
Gas gathering, processing and
transportation 1.43 0.66 114 % 1.28 0.82 55 %
Production and ad valorem taxes 1.50 1.81 (17) % 1.58 2.07 (24) %
Depreciation, depletion and
amortization 13.76 14.80 (7) % 15.36 16.32 (6) %


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Lease Operating and Gas Gathering, Processing and Transportation
The table below provides detail of our lease operating and gas gathering,
processing and transportation expenses for the three and nine months ended
September 30, 2020 and 2019:

Three Months Ended September 30, Nine Months Ended September 30,
In thousands 2020 2019 Change 2020 2019 Change
Lease operating $ 4,763 $ 8,948 (47) % $ 16,430 $ 23,472 (30) %
Gas gathering, processing and
transportation 1,891 1,107 71 % 4,916 3,223 53 %
Total lease operating and gas
gathering, processing and
transportation expenses $ 6,654 $ 10,055 (34) % $ 21,346 $ 26,695 (20) %



Lease operating and gas gathering, processing and transportation expenses are
the costs incurred in the operation of producing properties and workover costs.
Expenses for direct labor, water injection and disposal, utilities, materials
and supplies comprise the most significant portion of our lease operating
expenses. Lease operating expenses do not include general and administrative
expenses or production and ad valorem taxes.
Our lease operating and gas gathering, processing and transportation expenses
decreased $3.4 million, or 51%, for the three months ended September 30, 2020 to
$6.7 million from $10.1 million in the comparable period in 2019. On a
nine-month comparative basis, these expenses decreased $5.4 million, or 20%,
from $26.7 million in 2019 to $21.3 million in 2020. On a unit-of-production
basis, lease operating and gas gathering expense decreased 33%, or $1.78 per
BOE, from $5.37 per BOE in the three months ended September 30, 2019 to $3.59
per BOE in the three months ended September 30, 2020. On a nine-month
comparative basis, these expenses decreased 18%, or $1.25 per BOE, from $6.79
per BOE for the nine months ended September 30, 2019 to $5.54 per BOE for the
nine months ended September 30, 2020. Starting in March 2020, we deferred most
workover operations and replaced all third-party roustabout crews with company
employees. We also significantly cut field labor overtime and third-party costs
for water disposal, chemicals and rentals. Gas gathering, processing and
transportation expense increased for both the three and nine-month periods due
to the Company utilizing additional gas processing units starting in late 2019.
Compared to the second quarter of 2020, lease operating and gas gathering,
processing and transportation expenses increased 37%, or $1.8 million. On a
unit-of-production basis, these expenses increased 24%, or $0.98 per BOE, from
the second quarter of 2020.
Production and Ad Valorem Taxes
Production taxes are paid on produced crude oil and natural gas based upon a
percentage of gross revenues or at fixed rates established by state or local
taxing authorities. In general, the production taxes we pay correlate to the
changes in oil and natural gas revenues. We are also subject to ad valorem taxes
in the counties where our production is located. Ad valorem taxes are generally
based on the valuation of our oil and natural gas properties.

The following table provides detail of our production and ad valorem taxes for
the three and nine months ended September 30, 2020 and 2019:

Three Months Ended September 30, Nine Months Ended September 30,
In thousands 2020 2019 Change 2020 2019 Change
Production taxes $ 1,343 $ 1,860 (28) % $ 3,398 $ 5,958 (43) %
Ad valorem taxes 651 1,157 (44) % 2,687 2,168 24 %
Total production and ad valorem
tax expense $ 1,994 $ 3,017 (34) % $ 6,084 $ 8,126 (25) %


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Our total production and ad valorem tax expense decreased 34%, or $1.0 million,
between the three months ended September 30, 2020 and 2019. On a nine-month
comparative basis, these expenses decreased 25%, or $2.0 million, from $8.1
million in 2019 to $6.1 million in 2020. Production taxes were lower in the
current period due to significantly lower revenues, caused by lower commodity
prices and production as discussed above. Ad valorem taxes were higher in the
current year due to higher estimated appraisal values for our properties. On a
unit-of-production basis, production and ad valorem tax expense decreased 17%,
or $0.31 per BOE, from $1.81 per BOE in the three months ended September 30,
2019 to $1.50 per BOE in the three months ended September 30, 2020. On a
nine-month comparative basis, these expenses decreased 24%, or $0.49 per BOE,
from $2.07 per BOE for the nine months ended June 30, 2019 to $1.58 per BOE for
the nine months ended September 30, 2020. These decreases in the per-BOE rate
are attributable to lower commodity prices received for our production in the
current period, as further discussed above.
Compared to the second quarter of 2020, production and ad valorem taxes
increased $0.3 million, or 16%. This increase correlates with the increase in
production revenues between the two quarters, as a significant amount of the
Company's production was shut-in during the second quarter due to low commodity
prices, as discussed further above. On a unit-of-production basis, these
expenses increased 5%, or $0.08 per BOE, from the second quarter of 2020.
Depreciation, Depletion and Amortization
The table below provides detail of our depreciation, depletion and amortization
("DD&A") expense for the three and nine months ended September 30, 2020 and
2019.
Three Months Ended September 30, Nine Months Ended September 30,
In thousands 2020 2019 Change 2020 2019 Change
Depletion of proved oil and gas
properties $ 17,512 $ 24,178 (28) % $ 57,113 $ 62,813 (9) %
Depreciation of other property and
equipment 425 378 12 % 1,171 1,071 9 %
Accretion of asset retirement
obligations 319 79 304 % 900 236 281 %
Total DD&A expense $ 18,256 $ 24,635 (26) % $ 59,184 $ 64,120 (8) %


Capitalized costs attributed to our proved properties are subject to
depreciation and depletion calculated using the unit-of-production method. For
leasehold acquisition costs and the cost to acquire proved properties, the
reserve base used to calculate depreciation and depletion is the sum of proved
developed reserves and proved undeveloped reserves. For well costs, the reserve
base used to calculate depletion and depreciation is proved developed reserves
only. Other property and equipment are carried at cost, and depreciation is
calculated using the straight-line method over the estimated useful lives of the
assets, ranging from three to five years.
DD&A expense for the three months ended September 30, 2020 was $18.3 million, a
26% decrease from $24.6 million in the comparable period in 2019. On a
unit-of-production basis, DD&A decreased 8%, or $1.04 per BOE, from $14.80 per
BOE for the three months ended September 30, 2019 to $13.76 per BOE for the
three months ended September 30, 2020. On a nine-month comparative basis, these
expenses increased $4.9 million, or 8%, from $64.1 million for the nine months
ended September 30, 2019 to $59.2 million for the nine months ended September
30, 2020. On a unit-of-production basis, these expenses decreased 6% or $0.96
per BOE, from $16.32 per BOE for the nine months ended September 30, 2019, to
$15.36 per BOE for the nine months ended September 30, 2020. These decreases are
largely due to impairment charges we incurred during the first quarter of 2020
after removing PUDs (see below), as well as lower production between the two
periods.

Compared to the second quarter of 2020, DD&A expense increased $1.7 million. On
a unit-of-production basis, DD&A decreased by $0.11 per BOE, or 1%, from the
second quarter of 2020.

Loss on Sale of Oil and Gas Properties
In March 2019, we completed the divestiture of its Pirate assets in Wilson
County for an adjusted cash purchase price of $11.5 million, after closing
adjustments, to a private third-party. The assets were comprised of 3,400 net
undeveloped acres, six producing wells, held seven proved undeveloped locations
as of the closing date, and were producing approximately 200 BOE/d. We
recognized a loss of $33.5 million during the first quarter of 2019 in
conjunction with the sale of the assets.

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Impairment of Oil and Gas Properties
We evaluate impairment of proved and unproved oil and gas properties on a region
basis. On this basis, certain regions may be impaired because they are not
expected to recover their entire carrying value from future net cash flows.
During the first quarter of 2020, we recorded impairment charges totaling
approximately $199.9 million across various Eagle Ford properties, of which
$199.0 million was proved and $0.9 million was unproved. These impairments
resulted from removing PUDs and probable reserves from future development plans
due to the continued depressed commodity prices and the uncertainly of Company's
liquidity situation.
It is reasonably possible that the Company's estimate of undiscounted future net
cash flows may change in the future resulting in the need to impair the carrying
value of its properties. See Part II Item 1A. Risk Factors, for further
discussion.
General and Administrative
General and administrative ("G&A") expense increased $11.7 million, or 283%, to
$15.8 million in the three months ended September 30, 2020, from $4.1 million
for the comparable period in 2019. On a unit-of-production basis, G&A expense
increased 381%, or $9.44 per BOE, from $2.48 per BOE for the three months ended
September 30, 2019 to $11.92 per BOE for the three months ended September 30,
2020. On a nine-month comparative basis, G&A increased $12.3 million, or 100%,
between the two periods. On a unit-of-production basis, these expenses increased
104%, or $3.26 per BOE, from $3.14 per BOE for the nine months ended September
30, 2019, to $6.40 per BOE for the nine months ended September 30, 2020. These
increases primarily reflect professional fees incurred related to our
restructuring efforts during the second and third quarters of 2020, which
totaled $12.4 million and $14.3 million for the three and nine months ended
September 30, 2020, respectively.

Compared to the second quarter of 2020, G&A expense for the three months ended
September 30, 2020 increased $9.8 million, or 164%. On a unit-of-production
basis, G&A expense increased by $6.99 per BOE, or 142%, from the second quarter
of 2020.

Interest Expense
The table below provides detail of the interest expense for our various
long-term obligations for the three and nine months ended September 30, 2020 and
2019:
Three Months Ended September 30, Nine Months Ended September 30,
In thousands 2020 2019 Change 2020 2019 Change
Interest expense on 11.25% Senior
Notes $ 7,032 $ 7,032 - % $ 21,094 $ 21,094 - %
Interest expense on Credit
Facility 3,642 3,494 4 % 10,234 9,317 10 %
Other interest expense 98 136 (28) % 191 368 (48) %

Total cash interest expense (1) $ 10,772 $ 10,662

1 % $ 31,519 $ 30,779 2 %
Amortization of debt issuance
costs and discounts 627 633 (1) % 2,002 1,950 3 %
Total interest expense $ 11,399 $ 11,295 1 % $ 33,521 $ 32,729 2 %
Per BOE:
Total cash interest expense $ 8.12 $ 6.40 27 % $ 8.18 $ 7.83 4 %
Total interest expense 8.59 6.78 27 % 8.70 8.33 4 %


(1) Cash interest is presented on an accrual basis.
Our total interest expense in the three months ended September 30, 2020 was
$11.4 million, an 1% increase from $11.3 million in the comparable period in
2019. This slight increase is primarily due to lower interest rates on our
Credit Facility (as defined below), mostly offset by a higher outstanding
balance on the Credit Facility in the current quarter. On a nine-month
comparative basis, total interest expense increased $0.8 million, or 2%, between
the two periods.
On a unit-of-production basis, total interest expense increased 27%, or $1.81
per BOE, from $6.78 per BOE in the three months ended September 30, 2019 to
$8.59 per BOE in the three months ended September 30, 2020. On a nine-month
comparative basis, total interest expense increased 4%, or $0.37 per BOE, from
$8.33 per BOE for the nine months ended September 30, 2019 to $8.70 per BOE for
the nine months ended September 30, 2020.
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Compared to the second quarter of 2020, interest expense for the three months
ended September 30, 2020 increased by $0.9 million, primarily due to higher
average borrowings on our Credit Facility. On a unit-of-production basis,
interest expense decreased 1%, or $0.07 per BOE, from the second quarter of
2020.
As noted above, we did not make our $14.1 million cash interest payment due on
July 1, 2020 for the 11.25% senior notes, and additional interest expense for
the 11.25% Senior Notes will not be recorded subsequent to commencement of the
Chapter 11 Cases on September 30, 2020.
Income Taxes
The following table provides further detail of our income taxes for the three
and nine months ended September 30, 2020 and 2019:
In thousands, except per-BOE amounts Three Months Ended September 30, Nine Months Ended September 30,
and tax rates 2020 2019 2020 2019
Current income tax benefit (expense) $ 49 $ (18) $ 4,999 $ 26
Deferred income tax benefit
(expense) - (4,749) 737 6,940
Total income tax benefit (expense) $ 49 $ (4,767) $ 5,736 $ 6,966
Average income tax benefit (expense)
per BOE $ 0.04 $ (2.86) $ 1.49 $ 1.77
Effective tax rate 0.1 % 22.7 % 3.0 % 19.3 %

Total net deferred tax liability on
balance sheet at period end $ - $

5,387

As a result of the loss before income taxes of $34.9 million and $191.9 million
for the three and nine months ended September 30, 2020, respectively, we
recorded income tax benefit of $0.1 million and $5.7 million, respectively. As a
result of the net income before income taxes of $21.0 million for the three
months ended September 30, 2019 and net loss before income taxes of $36.0
million for the nine months ended September 30, 2019, we recorded income tax
expense of $4.8 million and income tax benefit $7.0 million, respectively.

On March 27, 2020, Congress enacted the Coronavirus Aid, Relief, and Economic
Security Act (the "CARES Act") to provide certain taxpayer relief as a result of
the COVID-19 pandemic. The CARES Act included several favorable provisions that
impacted income taxes, primarily the modified rules on the deductibility of
business interest expense for 2019 and 2020, a five-year carryback period for
net operating losses generated after 2017 and before 2021, and the acceleration
of refundable alternative minimum tax credits. The CARES Act did not materially
impact our effective tax rate for the three and nine months ended September 30,
2020.
Our deferred tax assets exceeded our deferred tax liabilities at September 30,
2020 primarily due to tax consequences of the impairment of our proved
properties during the first quarter of 2020; as a result, we retained a full
valuation allowance of $44.9 million at September 30, 2020 due to uncertainties
regarding the future realization of our deferred tax assets. The valuation
allowance is also the primary cause for the variance between our statutory tax
rate of 21% and the effective tax rates of 0.1% and 3.0% for the three and nine
months ended September 30, 2020, respectively. The valuation allowance will
continue to be recognized until the realization of future deferred tax benefits
is determined to be more likely than not.
We have prepared and filed a net operating loss carryback claim on which a
refund of $4.4 million has been requested for taxes originally paid with our
2016 income tax return. Due to the full valuation allowance recorded against our
net deferred tax asset, we have recognized income tax benefit of $4.4 million to
record the expected refund. The $4.4 million receivable has been classified as a
current income tax receivable in Prepaid Expenses and Other on our September 30,
2020 balance sheet.

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CAPITAL RESOURCES AND LIQUIDITY
Overview
At September 30, 2020, we had $36.6 million of cash on hand and $65.0 million of
stockholders' deficit, while at December 31, 2019, we had $3.1 million of cash
on hand and $120.9 million of stockholders' equity. In September 2020, we took
steps to ensure we had sufficient liquidity to fund ongoing operations during
the Chapter 11 Cases, and pay down our Credit Facility to provide additional
liquidity, by terminating our commodity and interest rate hedges for $30.5
million of cash (comprised of $39.9 million for oil swaps, offset by negative
$6.7 million for natural gas swaps and negative $2.7 million for interest rate
swaps). Subsequent to filing our Restructuring Plan, we entered into new natural
gas swaps in October 2020 for January 2021 through December 2021, which hedge
10,000 MMBtu per day at an average price of $3.04 per MMBtu, and also entered
into natural gas swaps for January 2022 through December 2022, which hedge 5,000
MMBtu per day at an average price of $2.70 per MMBtu. In November 2020, we
entered into new crude oil swaps for December 2020, which hedge 4,000 barrels
per day at an average price of $41.08 per barrel. We also entered into new crude
oil swaps for January 2021 through December 2021, which hedge 1,000 barrels per
day at an average price of $42.20 per barrel. We will continue to rebuild our
commodity derivatives portfolio as we emerge from the Chapter 11 Cases and
economic conditions warrant.

As discussed above, NYMEX oil prices have decreased significantly since the
beginning of 2020, decreasing from nearly $60 per barrel in early January to
around $25 per barrel in mid-May (although considerably lower during the month
of April 2020), before rebounding to nearly $40 per Bbl at the end of June 2020.
As of mid-November 2020, oil prices remained in the mid-$40s per Bbl due to
continued downward pressure on demand because of COVID-19. This decrease in the
market prices for our production directly reduces our operating cash flow and
indirectly impacts our other sources of potential liquidity, such as possibly
lowering our borrowing capacity under our revolving credit facility, as our
borrowing capacity and borrowing costs are generally related to the estimated
value of our proved reserves.

In this low oil price environment, we have taken various steps to preserve our
liquidity including (1) reducing our budgeted 2020 capital spending from $80-$85
million to approximately $65 million, almost all of which had been incurred by
the end of September 2020; (2) deferring the remainder of our 2020 drilling
program through the end of the year; (3) implementing cost-reduction measures,
including negotiating reduced rates for water disposal, chemicals, rentals, and
workovers and (4) shutting in or storing approximately 4,700 BOE per day of
production during late-April and all of May 2020, primarily at our oil-rich
fields in our Central Eagle Ford Area.

Chapter 11 Cases and Effect of Automatic Stay

On September 30, 2020, the Debtors filed for relief under chapter 11 of the
Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy
constituted an immediate event of default under our Credit Facility and the
indentures governing our 11.25% Senior Notes, resulting in the automatic and
immediate acceleration of the debt thereunder. Any efforts to enforce payment
obligations related to the acceleration of our debt have been automatically
stayed as a result of the filing of the Chapter 11 Cases, and the creditors'
rights of enforcement are subject to the applicable provisions of the Bankruptcy
Code. See Note 1. Basis of Presentation footnotes in the notes to the condensed
consolidated financial statements for more information on the Chapter 11 Cases.

On September 14, 2020, the Debtors entered into the RSA with certain holders of
our 11.25% Senior Notes the lenders of our Credit Facility and Citibank, N.A.,
as agent under the Credit Facility. As more fully disclosed in Note 1. Basis of
Presentation in the notes to the condensed consolidated financial statements,
the RSA contemplates the consummation of the Restructuring Plan, which governs
the treatment of certain claims and existing equity interests.

We expect to continue operations in the normal course for the duration of the
Chapter 11 Cases. To ensure ordinary course operations, we have obtained
approval from the Bankruptcy Court for certain "first day" motions, including
motions to obtain customary relief intended to continue our ordinary course
operations after the filing date. In addition, we have received authority to use
cash collateral of the lenders under the Credit Facility on a final basis. The
Bankruptcy Court confirmed our Restructuring Plan on November 12, 2020.

However, for the duration of the Chapter 11 Cases, our operations and our
ability to develop and execute our business plan are subject to a high degree of
risk and uncertainty associated with the Chapter 11 Cases. The outcome of the
Chapter 11 Cases is dependent upon factors that are outside of our control,
including actions of the Bankruptcy Court and our creditors. The significant
risks and uncertainties related to our liquidity and Chapter 11 Cases described
above raise substantial doubt about our ability to continue as a going concern.


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As a result of the Chapter 11 Cases, our total available liquidity at September
30, 2020 consisted of our $36.6 million of cash on hand. We expect to continue
using cash on hand which will further reduce this liquidity. With the Bankruptcy
Court's authorization to use cash collateral under the Credit Facility, we
believe that we will have sufficient liquidity, including cash on hand and funds
generated from ongoing operations, to fund anticipated cash requirements through
the Chapter 11 Cases. As such, we expect to pay vendor and royalty obligations
on a go-forward basis according to the terms of our current contracts and
consistent with applicable court orders, if any, approving such payments.

Going Concern

Our condensed consolidated financial statements 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 filing of the Chapter 11 Cases constituted an event of default under our
11.25% Senior Notes and Credit Facility, which resulted in the automatic and
immediate acceleration of all of our debt outstanding with the exception of the
building loans held by our subsidiary, Boland Building, LLC and certain small
financing loans. We project that we will not have sufficient cash on hand or
available liquidity to repay such debt. These conditions and events, along with
uncertainties associated with the bankruptcy process, raise substantial doubt
about our ability to continue as a going concern.

Our ability to continue as a going concern is contingent upon, among other
things, our ability to implement the Restructuring Plan, successfully emerge
from the Chapter 11 Cases and generate sufficient liquidity from the
Restructuring to meet our obligations and operating needs on an ongoing basis.
As a result of risks and uncertainties related to the effects of disruption from
the Chapter 11 Cases making it more difficult to maintain business, financing
and operational relationships, we have concluded that our plans do not alleviate
substantial doubt regarding the Company's ability to continue as a going
concern.

The condensed consolidated financial statements do not include any adjustments
relating to the recoverability and classification of recorded asset amounts or
the amounts and classification of liabilities that might result from the outcome
of this uncertainty.

Exit Financing

The Restructuring Plan contemplates, among other things, that, on the effective
date of the Restructuring Plan, the Debtors shall enter into (a) a first-out
senior secured revolving credit facility in an amount equal to 80% of the
aggregate outstanding principal amount of loans and letter of credit exposure
under the existing Credit Facility with any lender under the Credit Facility
that agrees to accept the Restructuring Plan (the "Accepting Lenders"); provided
that, on the Plan effective date, the aggregate principal amount of the new
revolving credit facility shall not be less than $152 million, (b) a
second-out-senior-secured term loan credit facility in an amount equal to 20% of
the aggregate outstanding principal amount of loans and letter of credit
exposure under the Company's existing Credit Facility of Accepting Lenders, and
(c) if necessary, a last-out-senior-secured term loan credit facility in an
amount equal to 100% of the aggregate outstanding principal amount of loans and
letters of credit of any lenders under the existing Credit Facility that do not
accept the Restructuring Plan or otherwise are not Accepting Lenders. As all
lenders accepted, we anticipate that there will not be a last-out-senior secured
term loan credit facility.

Cash Flows

Cash flows for the nine months ended September 30, 2020 and 2019 are presented
below:
Nine Months Ended June 30,
In thousands 2020 2019
Net cash provided by (used in):
Operating activities $ 82,731 $ 52,873
Investing activities (89,260) (116,569)
Financing activities 40,003 61,782
Net change in cash $ 33,474 $ (1,914)


34

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Net Cash Provided by Operating Activities
Net cash provided by operating activities of $82.7 million for the first nine
months of 2020 was $29.8 million more than the first nine months of 2019, which
totaled $52.9 million. Excluding changes in operating assets and liabilities,
net cash provided by operating activities increased $7.0 million. Compared to
the first nine months of 2019, the first nine months of 2020 had significantly
lower commodity prices. Changes in our operating assets and liabilities between
the nine months ended September 30, 2019 and the nine months ended September 30,
2020 resulted in a net increase of approximately $22.9 million in net cash
provided by operating activities for the nine months ended September 30, 2020,
as compared to the nine months ended September 30, 2019. As noted above, net
cash provided by operating activities includes $30.5 million of net cash
settlements in September 2020 arising from the termination of the Company's
hedge portfolio.
Net Cash Used in Investing Activities
Net cash used in investing activities decreased $27.3 million, from $116.6
million in the nine months ended September 30, 2019 to $89.3 million in the nine
months ended September 30, 2020. This is primarily due to capital expenditures
being $21.3 million less in the current period due to the slowdown in
development activity in light of lower commodity prices in 2020.
Net Cash Provided by Financing Activities
Net cash provided by financing activities decreased $21.8 million, from $61.8
million provided during the nine months ended September 30, 2019 to $40.0
million provided in the nine months ended September 30, 2020. This increase is
primarily due to lower borrowings on our Credit Line in the current period.
Debt
Chapter 11 Cases and Effect of Automatic Stay

On September 30, 2020, the Debtors filed for relief under chapter 11 of the
Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy
constituted an immediate event of default under the Credit Facility (as defined
below) and the indentures governing the Company's 11.25% Senior Notes (as
defined below), resulting in the automatic and immediate acceleration of the
debt. Any efforts to enforce payment obligations related to the acceleration of
the Company's debt have been automatically stayed as a result of the filing of
the Chapter 11 Cases, and the creditors' rights of enforcement are subject to
the applicable provisions of the Bankruptcy Code. See Note 1. Basis of
Presentation for more information on the Chapter 11 Cases.

Senior Secured Credit Facility

In July 2015, through its subsidiary, Lonestar Resources America, Inc. ("LRAI"),
the Company entered into a $500 million Senior Secured Credit Facility with
Citibank, N.A., as administrative agent, and other lenders party thereto (as
amended, supplemented or modified from time to time, the "Credit Facility"). As
of September 30, 2020, $285.0 million was borrowed under the Credit Facility,
and the weighted average interest rate on borrowings under the Credit Facility
for the quarter was 4.98%. Prior to default, the borrowing availability was
$0.6 million, which reflected $0.4 million of letters of credit outstanding. As
a result of the commencement of the Chapter 11 Cases, the we are not in
compliance with the covenants under the Credit Facility and the lenders'
commitments under the Credit Facility have been terminated. We are therefore
unable to make additional borrowings or issue additional letters of credit under
the Credit Facility.

Prior to default, the Credit Facility could be used for loans and, subject to a
$2.5 million sub-limit, letters of credit, and provided for a commitment fee of
0.375% to 0.5% (0.5% following the Thirteenth Amendment (as defined below))
based on the unused portion of the borrowing base under the Credit Facility. As
of March 31, 2020, the borrowing base and lender commitments for the Credit
Facility was $290 million. The borrowing base was lowered to $286 million on
June 11, 2020 as part of the Thirteenth Amendment. The borrowing base was
further lowered to $225 million pursuant to the Forbearance Agreement on July 2,
2020, creating a deficiency between the outstanding amount borrowed under the
Company's Credit Facility and the borrowing base. The outstanding balance under
the Credit Facility was $285 million as of September 30, 2020 which represents a
borrowing deficiency of $60.4 million. Pursuant to the Restructuring Plan and as
a result of our filing of the Chapter 11 Cases, we did not have the obligation
to pay such deficiency within that time period, and the Credit Facility will be
amended and restated in connection with the our exit from bankruptcy.


35
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Borrowings under the Credit Facility, at our election, bear interest at either:
(i) an alternate base rate ("ABR") equal to the higher of (a) the Prime Rate,
(b) the Federal Funds Effective Rate plus 0.5% per annum, and (c) the adjusted
LIBO rate of a three-month interest period on such day plus 1.0%; or (ii) the
adjusted LIBO rate, which is the rate stated on Reuters screen LIBOR1 page, for
one, two, three, six or twelve months, as adjusted for statutory reserve
requirements for Eurocurrency liabilities, plus, in each of the cases described
in clauses (i) and (ii) above, an applicable margin ranging from 1.0% to 2.0%
(2.0% to 3.5% following the Thirteenth Amendment) for ABR loans and from 2.0% to
3.0% (3.0% to 4.5% following the Thirteenth Amendment) for adjusted LIBO rate
loans.

Subject to certain permitted liens, our obligations under the Credit Facility
are required to be secured by the grant of a first priority lien on no less than
80% of the value of the proved oil and gas properties of the Company and its
subsidiaries (currently 100% following the Thirteenth Amendment).

The Credit Facility contains certain financial performance covenants, as defined
in the Credit Facility, including the following:

•A maximum debt to EBITDAX ratio of 4.0 to 1.0, and

•A current ratio of not less than 1.0 to 1.0.

We also were not in compliance with the terms of the Credit Facility as of
December 31, 2019 because we did not satisfy the consolidated current ratio at
those times and the audit report prepared by our auditors with respect to the
2019 financial statements included an explanatory paragraph expressing
uncertainty as to our ability to continue as a "going concern." The lenders
waived the current ratio default with respect to December 31, 2019. We received
a forbearance until July 31, 2020 for the defaults in the consolidated current
ratio covenant as of the March 31, 2020, and June 30, 2020, measurement dates,
the leverage ratio covenant as of the June 30, 2020, measurement date and the
missed interest payment under the 11.25% Senior Notes pursuant to the
Forbearance Agreement. We were not in compliance with the terms of the Credit
Facility as of May 15, 2020, because we did not timely deliver our financial
statements with respect to the fiscal quarter ended March 31, 2020. Such failure
represented a default under the Credit Facility which the lenders waived
pursuant to the Thirteenth Amendment. As noted above, the borrowing base was
redetermined to $225 million from $286 million pursuant to the Forbearance
Agreement on July 2, 2020, which created a deficiency between the outstanding
amount borrowed under the Credit Facility and the borrowing base.

Waiver and Eleventh Amendment

Effective April 7, 2020, we entered into the Waiver and Eleventh Amendment (the
"Waiver") to waive events of default arising from our failure to comply with the
consolidated current ratio as of December 31, 2019, to timely provide audited
financial statements and to provide financial statements that are not subject to
any "going concern" or like qualification or exception for the fiscal year ended
December 31, 2019. As there was no guarantee that our lenders would agree to
waive events of default or potential events of default in the future, the
amounts outstanding under the Credit Facility as of December 31, 2019 are
classified as current in the accompanying 2019 Condensed Consolidated Balance
Sheet.

Twelfth Amendment

Effective May 8, 2020, we entered into the Twelfth Amendment to Credit Agreement
(the "Twelfth Amendment"), to allow us to accept proceeds of up to $2.2 million
from an unsecured loan applied for under the CARES Act.

Waiver and Thirteenth Amendment

Effective June 11, 2020, we entered into the Waiver and Thirteenth Amendment to
Credit Agreement (the "Thirteenth Amendment") which, among other things, (i)
waived any default or event of default arising from our failure to provide
timely quarterly financial statements for the three months ended March 31, 2020;
(ii) redetermined the borrowing base to $286 million from $290 million; (iii)
set the next borrowing base redetermination to be on or around July 1, 2020 (and
in any event, no later than July 31, 2020), (iv) amended the borrowing base
utilization grid used in the applicable margin, as noted above and (v) until the
July 1, 2020 redetermination, restricted the Company and its subsidiaries'
ability to incur debt with respect to, among other items, capital leases and
permitted senior debt, grant liens to secure other obligations, pay dividends on
LRAI's preferred stock and make certain investments.


36
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Forbearance Agreement and Fourteenth Amendment

On July 2, 2020, we entered into a Forbearance Agreement, Fourteenth Amendment,
and Borrowing Base Agreement with Citibank, N.A., as administrative agent and
the lenders party thereto (the "Forbearance Agreement") with respect to the
Credit Facility. Pursuant to the Forbearance Agreement, among other things, (i)
the lenders under the Credit Facility agreed to refrain from exercising their
rights and remedies under the Credit Facility and related loan documents with
respect to certain defaults until July 31, 2020, (ii) the borrowing base was
redetermined to $225 million from $286 million, (iii) all proceeds of
dispositions and terminations or liquidations of swap agreements were to be used
to repay the Credit Facility and automatically reduced the borrowing base by the
amount of the repayment and (iv) certain exceptions to the covenant restriction
on investments were no longer available.

The rights of the lenders to exercise rights and remedies resulted from our
failure to comply with the current ratio with respect to the quarter ended March
31, 2020 and the defaults expected with respect to the quarter ending June 30,
2020, under the current ratio and the leverage ratio covenants, and the default
with respect to the failure to make the interest payment due on July 1, 2020,
under the 11.25% Senior Notes.

On July 31, 2020 the Company and certain of its subsidiaries entered into an
amendment with respect to the Forbearance Agreement with the Lenders, pursuant
to which the Lenders agreed to extend the stated term of the Forbearance
Agreement until August 21, 2020. On August 21, 2020, these parties agreed to
further extend the stated term of the Forbearance Agreement until September 11,
2020. The filing of the Chapter 11 Cases resulted in the acceleration of the
Credit Facility and the termination of the Forbearance Agreement. However,
pursuant to the RSA, the lenders under the Credit Facility agreed to forbear
from exercising certain rights and remedies while the RSA remains in full force
and effect.

11.25% Senior Notes

In January 2018, we issued $250 million of 11.25% Senior Notes to U.S.-based
institutional investors. The net proceeds of $244.4 million were used to fully
retire our 8.75% Senior Notes, which included principal, interest and a
prepayment premium of approximately $162 million. The remaining net proceeds
were used to reduce borrowings under the Credit Facility.

Prior to default, the 11.25% Senior Notes matured on January 1, 2023, and bore
interest at the rate of 11.25% per year, payable on January 1 and July of each
year. At any time prior to January 1, 2021, we could, on any one or more
occasions, redeem up to 35% of the aggregate principal amount of the 11.25%
Senior Notes with an amount of cash not greater than the net cash proceeds of
certain equity offerings at a redemption price equal to 111.25% of the principal
amounts redeemed, plus accrued and unpaid interest, provided that at least 65%
of the aggregate principal amount of 11.25% Senior Notes originally issued
remained outstanding immediately after such redemption and the redemption
occurred within 180 days of the closing date of such equity offering.

The indenture contains certain restrictions on our ability to incur additional
debt, pay dividends on our common stock, make investments, create liens on our
assets, engage in transactions with affiliates, transfer or sell assets,
consolidate or merge, or sell substantially all of our assets. The indenture
also contains cross-default provisions for defaults of our other debt
instruments, including the Credit Facility, caused by payment default or events
which cause the acceleration of repayment prior to the stated maturity of such
instrument.

We did not make its interest payment on the 11.25% Senior Notes that was due on
July 1, 2020 of approximately $14.1 million (the "Payment Default"). Such
failure to pay represented a default under the 11.25% Senior Notes and
represented an event of default when we did not cure within 30 days. The Payment
Default was a current event of default under the Credit Facility. We entered
into the Forbearance Agreement which provided that, among other things, the
lenders under the Credit Facility have agreed to forbear our default of the
interest payment until August 21, 2020.

On July 31, 2020, we entered into the Notes Forbearance Agreement pursuant to
which, among other things, certain holders holding greater than 50% of the
11.25% Senior Notes (i) agreed to refrain from exercising their rights and
remedies with respect to the Payment Default and (ii) requested that the trustee
not take any remedial action as a result of the Payment Default.

The filing of the Chapter 11 Cases resulted in the termination of the Notes
Forbearance Agreement and an event of default and acceleration of the maturity
of the 11.25% Senior Notes. However, pursuant to the RSA, certain holders of the
11.25% Senior Notes agreed to forbear from exercising certain rights and
remedies while the RSA is in full force and effect.

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Capital Expenditures
We currently anticipate that our full-year 2020 capital spending, excluding
acquisitions, will be approximately $65 million, almost all of which was
incurred by the end of September 2020. This program allowed for the drilling of
a range of 10 gross (7.0 net) wells and the completion of a range of 10 gross
(8.5 net) wells, five which were placed into production by the end of the first
quarter of 2020, two at Horned Frog and three at Hawkeye which were placed into
production during the second quarter of 2020 and three additional DUCs which
were drilled at Hawkeye during June 2020.
The table below summarizes our cash capital expenditures incurred for the nine
months ended September 30, 2020:
Three Months Ended Nine Months Ended
In thousands September 30, 2020 September 30, 2020
Acquisition of oil and gas properties $ 472 $ 2,186
Development of oil and gas properties (1) 25,149 97,973
Purchases of other property and equipment 378 1,014
Total capital expenditures $

25,999 $ 101,173

(1) On an accrual basis, the Company incurred $4.7 million $62.7 million in
development costs of oil and gas properties for the three and nine months ended
September 30, 2020, respectively.
For the nine months ended September 30, 2020, our capital expenditures were
funded with cash flow from operations, with additional funds provided by
borrowings on our Credit Facility. Our 2020 capital expenditures may be further
adjusted as business conditions warrant and the amount, timing and allocation of
such expenditures is largely discretionary and within our control. The aggregate
amount of capital that we will expend may fluctuate materially based on market
conditions, the actual costs to drill, complete and place on production operated
wells, our drilling results, other opportunities that may become available to us
and our ability to obtain capital.
Critical Accounting Policies and Estimates
The preparation of our financial statements requires us to make estimates and
judgments that can affect the reported amounts of assets, liabilities, revenues
and expenses, as well as the disclosure of contingent assets and liabilities at
the date of our financial statements. We analyze our estimates and judgments,
including those related to oil, NGLs and natural gas revenues, oil and natural
gas properties, impairment of long-lived assets, fair value of derivative
instruments, asset and retirement obligations and income taxes, and we base our
estimates and judgments on historical experience and various other assumptions
that we believe to be reasonable under the circumstances. Actual results may
vary from our estimates. The policies of particular importance to the portrayal
of our financial position and results of operations and that require the
application of significant judgment or estimates by our management are
summarized in the Management's Discussion and Analysis of Financial Condition
and Results of Operations section of our Annual Report on Form 10-K as reported
and filed with the SEC on April 13, 2020 (our "2019 10-K").
As of September 30, 2020, aside from the application of ASC 852 due to the
Chapter 11 Cases, there were no significant changes to any of our critical
accounting policies.
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Cautionary Note Regarding Forward-looking Statements
This Quarterly Report on Form 10-Q statement contains forward-looking statements
that are subject to a number of known and unknown risks, uncertainties, and
other important factors, many of which are beyond our control. We intend such
forward-looking statements to be covered by the safe harbor provisions for
forward-looking statements contained in Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of 1934. All statements,
other than statements of historical fact included in this Quarterly Report on
Form 10-Q, regarding our strategy, future operations, financial position,
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," "may,"
"continue," "predict," "potential," "project" and similar expressions are
intended to identify forward-looking statements, although not all
forward-looking statements contain such identifying words.
Forward-looking statements may include statements about our:
•our ability to consummate the Restructuring Plan;
•discovery and development of crude oil, NGLs and natural gas reserves;
• cash flows and liquidity;
• business and financial strategy, budget, projections and operating results;
• timing and amount of future production of crude oil, NGLs and natural gas;
• amount, nature and timing of capital expenditures, including future
development costs;
• availability and terms of capital;
• drilling, completion, and performance of wells;
• timing, location and size of property acquisitions and divestitures;
• costs of exploiting and developing our properties and conducting other
operations;
• general economic and business conditions; and
• our plans, objectives, expectations and intentions.
All forward-looking statements speak only as of the date of this Quarterly
Report on Form 10-Q. You should not place undue reliance on these
forward-looking statements. Although we believe that our plans, objectives,
expectations and intentions 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, objectives, expectations or intentions will
be achieved. We disclose important factors that could cause our actual results
to differ materially from our expectations under Item 1A. Risk Factors, Item 8.
Financial Statements and Supplementary Data and elsewhere in our 2019 Form 10-K,
and Part I. Financial Information, Item 1A. Risk Factors and elsewhere in this
Quarterly Report on Form 10-Q.
These important factors include risks related to:
•our ability to consummate the Restructuring Plan that restructures our debt
obligations to address our liquidity issues and allows emergence from the
Chapter 11 Cases;

• risks that our assumptions and analyses in the Restructuring Plan are
incorrect;

• the effects of the Chapter 11 Cases on our relationships with employees,
governmental authorities, customers, suppliers, banks, insurance companies and
other third parties, and agreements;

• potential adverse effects of the Chapter 11 Cases on our liquidity and results
of operations;

• objections to pleadings we file that could protract the Chapter 11 Cases;

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• our ability to continue as a going concern;

• the Bankruptcy Court's rulings in the Chapter 11 Cases, and the outcome of the
Chapter 11 Cases generally;

• the length of time that we will operate under Chapter 11 protection and the
continued availability of operating capital during the pendency of the
proceedings;

•variations in the market demand for, and prices of, crude oil, NGLs and natural
gas;
• proved reserves or lack thereof;
• estimates of crude oil, NGLs and natural gas data;
• the adequacy of our capital resources and liquidity including, but not
limited to, access to additional borrowing to fund our operations;
• borrowing capacity under our credit facility;
• general economic and business conditions;
• failure to realize expected value creation from property acquisitions;
• uncertainties about our ability to find, develop or acquire additional oil
and natural gas resources;
• uncertainties with regard to our drilling schedules;
• the expiration of leases on our undeveloped leasehold assets;
• our dependence upon several significant customers for the sale of most of our
crude oil, natural gas and NGL production;
• counterparty credit risks;
• competition within the crude oil and natural gas industry;
• technology risks;
• the concentration of our operations;
• drilling results;
• potential financial losses or earnings reductions from our commodity price
risk management programs;
• potential adoption of new governmental regulations;
• our ability to satisfy future cash obligations and environmental costs; and
• the other factors set forth under Risk Factors in Item 1A of Part I of our
2019 10-K.
The forward-looking statements relate only to events or information as of the
date on which the statements are made in this Quarterly Report on Form 10-Q.
Except as required by law, we undertake no obligation to update or revise
publicly any forward-looking statements, whether as a result of new information,
future events or otherwise, after the date on which the statements are made or
to reflect the occurrence of unanticipated events.
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