CHAPARRAL ENERGY, INC. Chaparral Energy, Inc. (NYSE: CHAP) is an independent oil and natural gas exploration and production company headquartered inOklahoma City . Founded in 1988, Chaparral has over 212,000 net surface acres in the Mid-Continent region. The Company is focused in the oil window of theAnadarko Basin in the heart ofOklahoma , where it has approximately 114,000 net acres (our "Focus Areas"). The following discussion and analysis is intended to assist in understanding our financial condition and results of operations for the three and six months endedJune 30, 2020 and 2019, as well as the current trends and uncertainties relevant to the Company's future financial and operational performance. The information should be read in conjunction with our unaudited consolidated financial statements and the notes thereto included in this quarterly report as well as the information included in our Annual Report on Form 10-K for the fiscal year endedDecember 31, 2019 . Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. For more information, see "Cautionary Note Regarding Forward-Looking Statements."
Early 2020 Activity
Early in the first quarter of 2020, Chaparral management began a comprehensive cash improvement effort. The initiative, which involves the formation and collaboration of multiple working teams, was intended to identify, validate and implement opportunities to improve the Company's cash flow across all parts of its business: drilling and completions capital expenditures, lease operating expenses, production uptime and efficiency, development planning, and general and administrative expenses. Many of the measures identified by the teams were implemented and expanded cash flow at the project level. However, because of the extraordinary and unprecedented events affecting the oil and gas industry discussed below, the benefits - which are scale-dependent - were not able to achieve their full potential.
Macroeconomic Developments and Their Impact on the Oil and Gas Industry
The energy industry has recently experienced two significant external forces that have impacted, and are anticipated to continue impacting, both day-to-day operations and the macro environment. The COVID-19 outbreak and voluntary and mandatory quarantines, travel restrictions and other restrictions throughoutthe United States and other parts of the world have resulted in decreased demand for crude oil, NGLs and natural gas. Additionally, inMarch 2020 , the group of oil producing nations known as OPEC+ failed to reach an agreement over proposed oil production cuts due to the decrease in global demand for oil stemming from the COVID-19 pandemic (the oil price war). Although the members of OPEC+ eventually reached an agreement to reduce their oil production beginning inMay 2020 and continuing throughApril 2022 , there remains significant uncertainty regarding the future actions of OPEC+, its members and other state-controlled oil companies related to oil price and production controls, including anticipated increases in supply fromRussia and other members of OPEC+, particularlySaudi Arabia . In addition, the COVID-19 pandemic has increased volatility and caused negative pressure in the capital and credit markets. As a result, we have not had the sort of access to the capital and credit markets that was once available to us. That lack of access to financing compounded the impact of the depressed commodity price environment triggered by COVID-19 and the oil price war.
Chaparral's Response and 2020 Outlook
In response to the depressed commodity price environment, Chaparral has taken material and unusual actions to maximize the value of its assets and improve its financial position. Because the Company had (a) a strong hedge position for crude oil in 2020, the terms of which did not require the physical delivery of any oil or gas and (b) no material volume commitments or other contractual obligations to produce oil or gas, we determined that it was not prudent or necessary to continue developing our inventory or to sell all of our products at the prevailing low market prices.
Shut-ins and Drilling Suspension. We suspended all drilling and stimulation
operations in early
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was performing above expectations. The Company subsequently shut in operated
production that is not associated with waterfloods or exposed to well-specific
mechanical or other risks during the months of May and June 2020 .
In order to facilitate a swift restart of sales, we took steps in April to
increase crude storage in the tank batteries at our operated lease locations. As
tank batteries filled, the majority of our operated production was curtailed.
Furthermore, as part of the April 2020 shut-in, we implemented procedures and
precautions to protect mechanical and reservoir integrity and to minimize the
cost and timing of resuming production. We wanted to ensure that production
could be resumed efficiently on these shut-in wells once commodity prices
recover sufficiently. With improved crude prices in June 2020 , the Company began
a phased restart to the curtailed production and by the end of the month nearly
all our operated wells had returned to production.
Hedging. The Company entered 2020 with a strong hedge position for crude oil in
2020. As prices declined sharply due to COVID-19 and the initial lack of a
coordinated response from OPEC+ to cut production, we generated $22.9 million
and $32.1 million in realized derivative gains for the three and six months
ended June 30, 2020 , respectively. However, we were unable to enter into new
hedges during the second quarter of 2020 as a result of a restriction imposed on
us by our hedging counterparties (who are also lenders under our Credit
Agreement) while our Borrowing Base Deficiency (as described below) remained
uncured. In July 2020 , we terminated all our outstanding derivatives, which we
discuss further below.
Liquidity and capital resources
Effect of Shut-ins and Drilling Suspension on Cash Flow from Operations. Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our revolving credit facility or issuance of debt, and proceeds from hedge settlements. As a result of shutting in a substantial number of our producing wells and suspending drilling and stimulation operations, cash flows generated from our operating activities declined significantly. This decline was partially offset by (a) the related reductions in expenses and capital expenditures and (b) proceeds from hedge settlements. Proceeds from Revolving Credit Facility and Senior Notes Interest Payment. In order to address the net reduction in cash flows discussed above, we significantly increased our cash balance by borrowing an additional$105 million at the beginning ofApril 2020 . These borrowings were made as a precautionary measure to increase our cash position and provide operational flexibility in the current challenging business environment. TheApril 2020 borrowings increased the total amount outstanding under our Credit Agreement to$250.0 million . Borrowing Base Deficiency and Past Due August Deficiency Payment. Shortly after we made these borrowings inApril 2020 , our lenders made an interim redetermination of the Company's borrowing base, reducing the borrowing base from$325.0 million to$175.0 million , effectiveApril 3, 2020 . The combination of the borrowing base reduction and ourApril 2020 borrowings created a$75.0 million borrowing base deficiency under the Credit Agreement (the "Borrowing Base Deficiency"). In accordance with the Credit Agreement, we elected to follow a procedure that permitted the Company to repay the$75.0 million deficiency in six equal monthly installments of$12.5 million , beginning in earlyMay 2020 . Since making that election, we have made three deficiency payments, for a total of$37.5 million . However, we did not make the fourth installment payment of$12.5 million that was due onAugust 3, 2020 (the "August Deficiency Payment"). The failure to make that payment on time resulted in an immediate event of default under the Credit Agreement, as well as under the cross-default provisions of the Indenture. Past Due Interest Payment on the Senior Notes. OnJuly 15, 2020 , the Company elected not to make the$13.125 million interest payment on the Senior Notes due on that day (the "Past Due Interest Payment"). Under the Indenture, the Company has a 30-day grace period to make the Past Due Interest Payment before that non-payment becomes an event of default. The Company subsequently did not make the Past Due Interest payment upon expiration of the 30-day grace period onAugust 14, 2020 . Even though the Indenture provides for a 30-day grace period to make the Past Due Interest Payment, the failure to make that interest payment on its due date ofJuly 15, 2020 constituted an immediate event of default under cross-default provisions of the Credit Agreement. The subsequent failure to make that interest payment upon expiration of the 30-day grace period onAugust 14, 2020 constituted an event of default under the indenture governing our Senior Notes (the "Indenture"). Lender Forbearance Agreement. OnJuly 15, 2020 , in order to address the cross-default that resulted under the Credit Agreement from the failure to timely pay the Past Due Interest Payment, the Company entered into a Limited Forbearance Agreement with the lenders under its Credit Agreement. The Limited Forbearance Agreement was amended effective as ofJuly 24, 2020 , by the First 37 -------------------------------------------------------------------------------- Amendment to Limited Forbearance Agreement (the "First Amendment") and was further amended effectiveJuly 29, 2020 by a Second Amendment (the "Second Amendment" and, as amended, such Limited Forbearance Agreement, the "Lender Forbearance Agreement"). OnAugust 14, 2020 , the Lender Forbearance Agreement was further amended by a Third Amendment (the "Third Amendment" and, as amended, such Lender Forbearance Agreement, the "Final Lender Forbearance Agreement"). Pursuant to the Final Lender Forbearance Agreement, the Lenders agreed, during the forbearance period, to forbear from exercising any remedies under the Credit Agreement for any default or event of default resulting from any failure by the Company or any of its subsidiaries to make all or any part of the Past Due Interest Payment (including the failure to make such payment during the 30-day grace period therefor). The Final Lender Forbearance Agreement also includes forbearance for the Company's failure to timely pay the August Deficiency Payment under the Credit Agreement and the failure to timely deliver the quarterly financial statements for the period endedJune 30, 2020 and the required accompanying officer's certificate. The forbearance period under the Final Lender Forbearance Agreement began onJuly 15, 2020 and was scheduled to expire onJuly 29, 2020 , unless terminated earlier in accordance with its terms. The scheduled expiration of the forbearance period was later extended toAugust 9, 2020 and, by mutual agreement between the Company the administrative bank for the credit facility, extended further toAugust 14, 2020 . The Third Amendment resulted in an final extension of the forbearance period toAugust 17, 2020 . Required Termination of Hedges and Partial Paydown of Credit Agreement. The Final Lender Forbearance Agreement required the Company to terminate all of its outstanding commodity hedges or beforeJuly 31, 2020 and to apply a certain portion of the proceeds thereof toward partial repayment of the outstanding amount under the Credit Agreement. To comply with this requirement, the Company unwound all of its hedge positions, resulting in total proceeds of$28.2 million (taking into account previously-settled hedge positions). Of this amount,$24.0 million was applied toward repayment on outstanding credit facility borrowings and the remainder was retained by the Company. Noteholder Forbearance Agreement. Effective as ofJuly 30, 2020 , to address the Company's expected cross-default under the Indenture resulting from the failure to timely pay the August Deficiency Payment under the Credit Agreement, the Company and the holders of at least 75% of the principal amount of outstanding Senior Notes (the "Initial Consenting Noteholders") entered into a Forbearance and Waiver Agreement (the "Noteholder Forbearance Agreement"). The forbearance period under the Noteholder Forbearance Agreement began onJuly 30, 2020 and was scheduled to expire onAugust 14, 2020 . Pursuant to the Noteholder Forbearance Agreement, the Initial Consenting Noteholders agreed, during the forbearance period, to forbear from exercising certain remedies under the Indenture (including acceleration) for any default or event of default resulting from any failure by the Company to pay the August Deficiency Payment under the Credit Agreement on or beforeAugust 3, 2020 . OnAugust 14, 2020 , the Company and the Initial Consenting Noteholders amended and restated the Noteholder Forbearance Agreement (such amendment and restatement, the "Amended and Restated Noteholder Forbearance Agreement"). Pursuant to the Amended and Restated Noteholder Forbearance Agreement, the Initial Consenting Noteholders agreed to extend the forbearance period toAugust 17, 2020 and to additionally forbear from exercising certain remedies under the Indenture (including acceleration) for any default or event of default resulting from any failure by the Company to make the required interest payment of$13.125 million within the 30-day grace period described above. Impact of Impending Expiration of Forbearance Periods. Both the Final Lender Forbearance Agreement and the Amended and Restated Noteholder Forbearance Agreement are scheduled to expire onAugust 17, 2020 . Therefore, before either of those forbearance agreements expired, the Company was effectively required to either (i) make a voluntary bankruptcy filing to take advantage of the automatic stay under Chapter 11 or (ii) make both the$12.5 million August Deficiency Payment and the$13.125 million Past Due Interest Payment. Restructuring Support Agreement and the Chapter 11 Cases. OnAugust 15, 2020 , we entered into a restructuring support agreement (the "RSA") with (i) the lenders under our Credit Agreement and (ii) certain holders of our Senior Notes (the "Restructuring Support Parties"). Pursuant to the RSA, the Restructuring Support Parties agreed, subject to the terms and conditions of the RSA, to vote to accept our prepackaged Joint Chapter 11 Plan of Reorganization (as proposed, our "Plan of Reorganization"). Our Plan of Reorganization and the related disclosure statement (the "Disclosure Statement") were each filed with theBankruptcy Court onAugust 16, 2020 . For more information on the RSA, see "Note 11: Subsequent events" in "Item 1: Financial Information" of this Quarterly Report on Form 10-Q. 38 -------------------------------------------------------------------------------- The commencement of a voluntary proceeding in bankruptcy through our filing of the Chapter 11 Cases constitutes an immediate event of default under the Credit Agreement and the Senior Notes, resulting in immediate acceleration of outstanding amounts under these debt instruments. Any efforts to enforce payment obligations related to the Company's debt, including the acceleration thereof, have been automatically stayed as a result of the Chapter 11 Cases, and the creditors' rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Furthermore, the filing of the Chapter 11 Cases caused the immediate termination of the Final Lender Forbearance Agreement and the Amended and Restated Noteholder Forbearance Agreement. To maintain and continue uninterrupted ordinary course operations during the bankruptcy proceedings, the we filed a variety of "first day" motions seeking approval from theBankruptcy Court for various forms of customary relief designed to minimize the effect of bankruptcy on our operations, customers and employees. Upon entry by theBankruptcy Court of the orders approving all requested "first day" relief, we will be able to conduct normal business activities and pay all associated obligations for the period following our bankruptcy filing and (subject to caps applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and vendors, royalty interest and working interest holders, and partners. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business require the prior approval of theBankruptcy Court .
Ability to Continue as a Going Concern
The Company projects that it will not have sufficient cash on hand or available liquidity to repay all debt that was accelerated through the filing of the Chapter 11 Cases. These conditions along with the significant risks and uncertainties related to the Company's liquidity and the Chapter 11 Cases raise substantial doubt about the Company's ability to continue as a going concern.
Exit Facility
Pursuant to the RSA, on the effective date of our Plan of Reorganization, the remaining borrowings under the Credit Agreement will constitute outstanding amounts under a$300,000 exit credit facility (the "Exit Facility"). The Exit Facility will include (A) second out term loans (the "Second Out Term Loans") in an amount to be determined, which will have a maturity date that is one year and 91 days following the Revolving Maturity Date (defined below) and (B) a revolving facility (the maturity date of which will be the earlier ofMay 31, 2024 or 40 months after emergence (the "Revolving Maturity Date")) that has an initial borrowing base equal to (i) the lesser of (a)$175,000 or (b) the Company's proved developed producing reserves on a PV-15 basis, plus hedges, on 6-month roll-forward basis minus (ii) the aggregate amount of the Second Out Term Loans. There must be a minimum of$20,000 of availability under the Exit Facility at emergence. Indebtedness Debt consists of the following as of the dates indicated: (in thousands) June 30, 2020 December 31, 2019 8.75% Senior Notes due 2023$ 300,000 $ 300,000 Credit facility 225,000 130,000 Financing lease obligations 1,442 1,653 Installment note payable - 371 Unamortized issuance costs (4,154) (10,038) Total debt, net$ 522,288 $ 421,986 Finance leases
We currently have financing leases that consist of fleet trucks and office
equipment. Please see "Note 17: Leases" in "Item 8. Financial Statements and
Supplementary Data" of our Annual Report on Form 10-K for the year ended
Sources and uses of cash
Our net change in cash is summarized as follows:
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Six months ended June 30,
(in thousands) 2020 2019
Cash flows (used in) provided by operating activities $ (9,419) $ 58,105
Cash flows used in investing activities (51,403) (144,924)
Cash flows provided by financing activities 94,364 82,021
Net increase (decrease) in cash during the period $ 33,542 $ (4,798)
Our cash flows from operating activities are derived substantially from the
production and sale of oil and natural gas. Cash flows from operating activities
for the six months ended June 30, 2020 , which was an outflow of $9.4 million ,
decreased compared to the prior year period primarily due to a reduction in
gross revenues, liability management expenses that we incurred and working
capital changes. These cash flow decreases were partially offset by lower lease
operating expenses and production taxes.
Our cash flows from investing activities typically consist of cash outflows for
capital expenditures, cash inflows from asset dispositions and derivative
settlement payments or receipts. During 2020, we relied on borrowings from our
credit facility, derivative receipts and cash on hand to fund our capital
expenditures.
Our actual costs incurred, including costs that we have accrued for during the
six months ended June 30, 2020 , are summarized in the table below.
(in thousands) Six months ended June 30, 2020
Acquisitions (1) $ 11,080
Drilling (2) 42,750
Enhancements 4,069
Operational capital expenditures incurred 57,899
Other (3)
6,952
Total capital expenditures incurred $
64,851
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(1)Includes$8.8 million recorded to unproved leasehold related to the drilling commitment obligation discussed above under "Contractual obligations." (2)Includes$0.7 million on development of wells operated by others. (3)For the six months endedJune 30, 2020 , this amount includes$2.9 million for capitalized general and administrative expenses, and$3.9 million for capitalized interest. Net cash used in investing activities during the six months endedJune 30, 2020 consisted of cash outflows for capital expenditure of$86.9 million partially offset by receipts for derivative settlements of$32.1 million and proceeds from asset sales of$3.4 million . Our cash outflows for capital expenditure are greater than our actual costs incurred for the period, disclosed in the table above, as a result of payments in the current period for expenditures accrued at the end of the prior year. Our asset sale proceeds primarily consisted of proceeds from equipment, vehicles and real estate previously classified as held-for-sale on our balance sheet. Net cash used in investing activities during the six months endedJune 30, 2019 consisted of cash outflows for capital expenditure of$146.4 million partially offset by receipts for derivative settlements of$0.7 million and proceeds from asset sales of$0.9 million . Net cash from financing activities during the six months endedJune 30, 2020 , consisted of borrowings on our credit facility of$120.0 million partially offset by cash outflows of$25.5 million for repayment of debt, including financing leases, and$0.1 million for debt financing fees. Net cash from financing activities during the six months endedJune 30, 2019 , consisted of borrowings on our credit facility of$85.0 million partially offset by cash outflows for repayment of debt and financing leases of$1.8 million and for treasury stock repurchases of$1.2 million .
Contractual obligations
We have numerous contractual commitments in the ordinary course of business
including debt service requirements, operating leases, financing leases, well
drilling obligations and purchase obligations. Our operating leases currently
consist of an office space lease at our headquarters and our financing leases
consist of leases on our fleet vehicles and office equipment. We have a well
drilling commitment under the terms of leasehold purchase agreements which we
entered into in 2017. The drilling commitment requires the Company to drill and
complete 10 wells on such leasehold in each of 2019, 2020, and 2021 and 15 wells
in 2022. To the extent the
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Company does not drill and complete the minimum number of wells in a given year,
it is required to pay the sellers of the acreage $250,000 for each deficient
well. The Company has paid the deficiency amount related to its 2019 drilling
commitment and recorded accruals of $2.5 million in March 2020 and $6.3 million
in June 2020 for the remaining obligation as it does not intend to drill any
further wells on the subject acreage.
Surety bonds totaling $2.1 million were posted on our behalf as of March 31,
2020 . We pay premiums for such bonds and, under normal circumstances, are not
required to post collateral of any kind to support their issuance. However, as a
result of the current extraordinary macroeconomic situation and the Borrowing
Base Deficiency discussed above, we have been required to post cash collateral
in respect of the bonds totaling $1.0 million as of June 30, 2020 .
Other than additional borrowings under our credit facility and the Borrowing
Base Deficiency described in "Note 4: Debt" in "Item 1: Financial Information"
of this Quarterly Report on Form 10-Q and the termination of our derivative
contracts in July 2020 , we have not had material changes to our contractual
commitments since December 31, 2019 .
Results of operations
Highlights
Our financial and operating performance in the second quarter of 2020 includes the following highlights and comparisons to the prior year quarter:
•We generated a net loss for the three months endedJune 30, 2020 , of$438.7 million . Included in our loss was a ceiling impairment of$384.6 million . •Our loss on commodity derivatives for the three months endedJune 30, 2020 , of$13.0 million was attributable to$35.9 million of noncash mark-to-market losses partially offset by$22.9 million in realized settlement gains. •Our net sales volume decreased 34% to 1,689 MBoe for the three months endedJune 30, 2020 , compared to the prior year quarter as we curtailed capital development and shut-in wells for a portion of the quarter in response to low commodity prices. •We lowered our lease operating expense by 55% to$6.0 million for the three months endedJune 30, 2020 , compared to the prior year quarter. The corresponding change on a per Boe basis was a decrease of 32% to$3.58 /Boe. •We incurred liability management expenses of$8.0 million from our activities to restructure our debt and in preparation for our Chapter 11 Case. •Our oil and natural gas capital expenditures for the six months endedJune 30, 2020 , were$64.9 million , with$42.8 million incurred for drilling and completions and$11.1 million on acquisitions. Our capital activity during the first half of the year included completing and bringing online 15 wells, of which nine were drilled in the current year and six in the prior year. We also drilled three wells scheduled to be completed subsequent to quarter end. •As a result of the defaults on our Senior Notes and Credit Agreement, we classified the entire outstanding amounts on those facilities as current liabilities on our condensed consolidated balance sheet.
Sales
Sales volumes by area were as follows (MBoe)
Three months ended June 30, Increase/ Percent
2020 2019 (Decrease) Change
Focus Areas:
Kingfisher County 462 646 (184) (28.5) %
Canadian County 732 1,125 (393) (34.9) %
Garfield County 169 343 (174) (50.7) %
Other 18 51 (33) (64.7) %
Total Focus Areas 1,381 2,165 (784) (36.2) %
Other 308 409 (101) (24.7) %
Total 1,689 2,574 (885) (34.4) %
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Six months ended June 30 , Increase/ Percent
2020 2019 (Decrease) Change
Focus Areas:
Kingfisher County 1,212 1,251 (39) (3.1) %
Canadian County 2,114 1,601 513 32.0 %
Garfield County 405 639 (234) (36.6) %
Other 54 108 (54) (50.0) %
Total Focus Areas 3,785 3,599 186 5.2 %
Other 697 849 (152) (17.9) %
Total 4,482 4,448 34 0.8 %
For the three months ended June 30, 2020 , our total net sales decreased compared
to the prior year quarter. The decreases were primarily due to our shut in of
wells for a portion of the quarter as a result the low pricing environment, our
suspension of capital development in late April 2020 , and natural decline. The
previously mentioned measures were taken as a response to the drastic commodity
price declines we have experienced recently as a result of COVID-19. For the six
months ended June 30, 2020 , our total sales was approximately flat compared to
the prior year period as the sales decline in the second quarter discussed above
was offset by sales increases primarily due to 38 operated wells that were
brought online since the second quarter of 2019.
Revenues and transportation and processing
Our commodity sales are derived from the production and sale of oil, natural gas
and natural gas liquids. These revenues do not include the effects of derivative
instruments and may vary significantly from period to period as a result of
changes in volumes of production sold or changes in commodity prices.
The following table presents information about our sales volumes and revenues
before the effects of commodity derivative settlements:
Three months ended June 30, Increase/ Percent
2020 2019 (Decrease) Change
Commodity sales (in thousands):
Oil $ 10,384 $ 50,990 $ (40,606) (79.6) %
Natural gas 5,679 10,476 (4,797) (45.8) %
Natural gas liquids 3,903 11,025 (7,122) (64.6) %
Gross commodity sales $ 19,966 $ 72,491 $ (52,525) (72.5) %
Transportation and processing (4,086) (5,784) 1,698 (29.4) %
Net commodity sales $ 15,880 $ 66,707 $ (50,827) (76.2) %
Production:
Oil (MBbls) 453 873 (420) (48.1) %
Natural gas (MMcf) 4,621 5,715 (1,094) (19.1) %
Natural gas liquids (MBbls) 466 749 (283) (37.8) %
MBoe 1,689 2,574 (885) (34.4) %
Average daily production (Boe/d) 18,562 28,286 (9,724) (34.4) %
Average sales prices (excluding
derivative settlements):
Oil per Bbl $ 22.92 $ 58.41 $ (35.49) (60.8) %
Natural gas per Mcf $ 1.23 $ 1.83 $ (0.60) (32.8) %
NGLs per Bbl $ 8.38 $ 14.72 $ (6.34) (43.1) %
Transportation and processing per
Boe $ (2.42) $ (2.25) $ (0.17) 7.6 %
Average sales price per Boe $ 9.40 $ 25.92
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Six months ended June 30, Increase/ Percent
2020 2019 (Decrease) Change
Commodity sales (in thousands):
Oil $ 47,410 $ 83,792 $ (36,382) (43.4) %
Natural gas 14,334 21,682 (7,348) (33.9) %
Natural gas liquids 13,585 20,242 (6,657) (32.9) %
Gross commodity sales $ 75,329 $ 125,716 $ (50,387) (40.1) %
Transportation and processing (10,598) (10,390) (208) 2.0 %
Net commodity sales $ 64,731 $ 115,326 $ (50,595) (43.9) %
Production:
Oil (MBbls) 1,293 1,491 (198) (13.3) %
Natural gas (MMcf) 11,071 10,189 882 8.7 %
Natural gas liquids (MBbls) 1,344 1,259 85 6.8 %
MBoe 4,482 4,448 34 0.8 %
Average daily production (Boe/d) 24,627 24,576 51 0.2 %
Average sales prices (excluding
derivative settlements):
Oil per Bbl $ 36.67 $ 56.20 $ (19.53) (34.8) %
Natural gas per Mcf $ 1.29 $ 2.13 $ (0.84) (39.4) %
NGLs per Bbl $ 10.11 $ 16.08 $ (5.97) (37.1) %
Transportation and processing per Boe $ (2.36) $ (2.34) $ (0.02) 0.9 %
Average sales price per Boe $ 14.44 $ 25.93 $ (11.49) (44.3) %
Our gross commodity sales (excluding transportation and processing deductions)
decreased for the three months ended June 30, 2020 , compared to the prior year
quarter due to volume and price decreases across all commodities. Our commodity
sales for the six months ended June 30, 2020 , decreased compared to the prior
year period due to price decreases across all commodities and a decrease in
crude oil volumes partially offset by volume increases for natural gas and NGLs.
The table below discloses the impact of price and production volume changes on
our revenues.
Six months ended June 30,
Three months ended June 30, 2020 vs. 2019 2020 vs. 2019
Percentage Percentage
Sales change Sales change
(in thousands) change in sales change in sales
Change in oil sales due to:
Prices $ (16,074) (31.5) % $ (25,254) (30.1) %
Volume (24,532) (48.0) % (11,128) (13.3) %
Total change in oil sales $ (40,606) (79.6) % $ (36,382) (43.4) %
Change in natural gas sales due to:
Prices $ (2,795) (26.7) % $ (9,227) (42.6) %
Volume (2,002) (19.1) % 1,879 8.7 %
Total change in natural gas sales $ (4,797) (45.8) % $ (7,348) (33.9) %
Change in natural gas liquids sales
due to:
Prices $ (2,956) (26.9) % $ (8,024) (39.6) %
Volume (4,166) (37.8) % 1,367 6.8 %
Total change in natural gas liquids
sales $ (7,122) (64.6) % $ (6,657) (32.9) %
Transportation and processing revenue deductions principally consist of
deductions by our customers for costs to prepare and transport production from
the wellhead to a specified sales point and processing costs of gas into natural
gas liquids. Transportation and processing deductions for the three months ended
June 30, 2020 , were lower than the prior year quarter due primarily to decreases
in natural gas and natural gas liquids volumes sold. Transportation and
processing deductions for the six months ended June 30, 2020 ,
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were relatively flat compared to the prior year quarter due primarily to natural
gas and natural gas liquids volumes remaining relatively flat over the two
periods.
Derivative activities
Our results of operations, financial condition and capital resources are highly
dependent upon the prevailing market prices of, and demand for, oil and natural
gas. These commodity prices are subject to wide fluctuations and market
uncertainties. To mitigate a portion of this exposure, we have entered into
various types of derivative instruments, including commodity price swaps and
costless collars.
Our realized prices are impacted by realized gains and losses resulting from
commodity derivatives contracts. The following table presents information about
the effects of derivative settlements on realized prices:
Three months ended June 30, Six months ended June 30,
2020 2019 2020 2019
Oil (per Bbl):
Before derivative settlements $ 22.92 $ 58.41 $ 36.67 $ 56.20
After derivative settlements $ 63.55 $
56.13
277.3 % 96.1 % 147.6 % 98.8 %
Natural gas liquids (per Bbl):
Before derivative settlements $ 8.38 $
14.72
$ 13.73 $
16.08
163.8 % 109.2 % 142.8 % 107.8 %
Natural gas (per Mcf):
Before derivative settlements $ 1.23 $
1.83
$ 1.67 $
2.03
135.8 % 110.9 % 126.4 % 100.0 %
The estimated fair values of our oil, natural gas, and NGL derivative instruments are provided below. The associated carrying values of these instruments are equal to the estimated fair values. (in thousands)
June 30, 2020 December 31 ,
2019
Derivative assets (liabilities): Crude oil derivatives$ 15,399 $ (21,805) Natural gas derivatives 1,788 3,551 NGL derivatives - 2,169
Net derivative assets (liabilities)
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Our derivative portfolio, which was in a net liability position at the end of
2019, reverted to a net asset of $17.2 million as of June 30, 2020 . The change,
which also corresponds to the non-cash fair value adjustment gain of $33.3
million in the table below, is primarily due to the steep decline in crude oil
forward prices brought on by the COVID-19 pandemic.
The effects of derivative activities on our results of operations and cash flows were as follows:
Three months ended June 30,
2020 2019
Non-cash Non-cash
fair value Settlements fair value Settlements
(in thousands) adjustment (paid) received adjustment (paid) received Derivative gains (losses): Crude oil derivatives
$ (30,036) $ 18,405 $ 11,466 $ (1,991) Natural gas derivatives (2,468) 2,017 4,889 1,113 NGL derivatives (3,430) 2,493 1,241 1,016 Derivative gains (losses)$ (35,934) $ 22,915 $ 17,596 $ 138 Six months ended June 30, 2020 2019 Non-cash Non-cash fair value Settlements fair value Settlements (in thousands) adjustment
(paid) received adjustment (paid) received Derivative gains (losses): Crude oil derivatives
$ 37,204 $ 22,561 $ (37,203) $ (980) Natural gas derivatives (1,763) 3,705 4,750 52 NGL derivatives (2,169) 5,823 (1,482) 1,581 Derivative gains (losses)$ 33,272 $ 32,089 $ (33,935) $ 653 We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as "Derivative gains (losses)" in our consolidated statements of operations. The fluctuation in derivative gains (losses) from period to period is due primarily to the significant volatility of oil, NGL and natural gas prices and to changes in our outstanding derivative contracts during these periods. Pursuant to the requirements of the Lender Forbearance Agreement, onJuly 27, 2020 , the Company terminated all its outstanding derivative contracts. Proceeds from the early termination along with amounts owed to the Company from previously settled positions totaled$28.2 million .
Lease operating expenses
Three months ended June 30, Increase/ Percent
(in thousands, except per Boe data) 2020 2019 (Decrease) Change
Lease operating expenses:
Focus Areas $ 3,082 $ 8,445 $ (5,363) (63.5) %
Other 2,889 4,926 (2,037) (41.4) %
Total lease operating expenses $ 5,971 $ 13,371 $ (7,400) (55.3) %
Lease operating expenses per Boe:
Focus Areas $ 2.23 $ 3.90 $ (1.67) (42.8) %
Other $ 9.38 $ 12.04 $ (2.66) (22.1) %
Lease operating expenses per Boe $ 3.54 $ 5.19 $ (1.65) (31.8) %
45
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Six months ended June 30, Increase/ Percent
(in thousands, except per Boe data) 2020 2019 (Decrease) Change
Lease operating expenses:
Focus Areas $ 8,691 $ 15,559 $ (6,868) (44.1) %
Other 7,368 10,106 (2,738) (27.1) %
Total lease operating expenses $ 16,059 $ 25,665 $ (9,606) (37.4) %
Lease operating expenses per Boe:
Focus Areas $ 2.30 $ 4.32 $ (2.02) (46.8) %
Other $ 10.57 $ 11.90 $ (1.33) (11.2) %
Lease operating expenses per Boe $ 3.58 $ 5.77 $ (2.19) (38.0) %
Lease operating expenses ("LOE") are sensitive to changes in demand for field
equipment, services, and qualified operational personnel, which is driven by
demand for oil and natural gas. However, the timing of changes in operating
costs may lag behind changes in commodity prices. LOE for the three months ended
June 30, 2020 was lower on a total dollar basis and on a per Boe basis compared
to the prior year quarter. The quarter over quarter decline in total LOE was
primarily due to a decrease in water hauling costs and reduced costs for well
maintenance. Our reduced well maintenance costs were primarily attributable to
our shut-ins of wells as part of our response to low commodity pricing. In
addition to these factors, LOE on a per Boe basis was also lower because of
increased production in areas with lower per Boe costs. LOE for the six months
ended June 30, 2020 was lower on a total dollar basis and on a per Boe basis due
to the same factors described above.
Production taxes (which include severance and ad valorem taxes)
Three months ended June 30, Increase/ Percent
2020 2019 (Decrease) Change
Production taxes (in thousands) $ 823 $ 3,802 $ (2,979) (78.4) %
Production taxes per Boe $ 0.49 $ 1.48 $ (0.99) (66.9) %
Production taxes as % of commodity
sales 4.1 % 5.2 %
Six months ended June 30, Increase/ Percent
2020 2019 (Decrease) Change
Production taxes (in thousands) $ 3,573 $ 6,682 $ (3,109) (46.5) %
Production taxes per Boe $ 0.80 $ 1.50 $ (0.70) (46.7) %
Production taxes as % of commodity
sales 4.7 % 5.3 %
Production taxes for the three months and six months ended June 30, 2020 were
lower than the prior year periods due to a decrease in commodity revenues driven
by volume and price declines as discussed above. The corresponding decreases on
a per Boe basis were primarily a result of lower commodity prices and a greater
percentage of revenues being derived from gas volumes, which yield a lower
revenue per Boe compared to crude oil and NGLs.
Depreciation, depletion and amortization ("DD&A")
Three months ended June 30, Increase/ Percent
2020 2019 (Decrease) Change
DD&A (in thousands):
Oil and natural gas properties (1) $ 14,388 $ 28,488 $ (14,100) (49.5) %
Property and equipment 433 1,794 (1,361) (75.9) %
Total DD&A $ 14,821 $ 30,282 $ (15,461) (51.1) %
DD&A per Boe:
Oil and natural gas properties (1) $ 8.52 $ 11.07 $ (2.55) (23.0) %
Other fixed assets 0.25 0.69 (0.44) (63.8) %
Total DD&A per Boe $ 8.77 $ 11.76 $ (2.99) (25.4) %
46--------------------------------------------------------------------------------
Six months ended June 30, Increase/ Percent
2020 2019 (Decrease) Change
DD&A (in thousands):
Oil and natural gas properties (1) $ 36,963 $ 50,369 $ (13,406) (26.6) %
Property and equipment 870 3,628 (2,758) (76.0) %
Total DD&A $ 37,833 $ 53,997 $ (16,164) (29.9) %
DD&A per Boe:
Oil and natural gas properties (1) $ 8.25 $ 11.32 $ (3.07) (27.1) %
Other fixed assets 0.19 0.82 (0.63) (76.8) %
Total DD&A per Boe $ 8.44 $ 12.14 $ (3.70) (30.5) %
_________________________________________
(1)Includes accretion of asset retirement obligations
We adjust our DD&A rate on oil and natural gas properties each quarter for changes in our estimates of oil and natural gas reserves and costs. Oil and natural gas DD&A for the three and six months endedJune 30, 2020 decreased compared to the prior year periods due to lower production and a lower DD&A rate. The DD&A rate declined due to prior ceiling test write-offs, which lowered the full cost amortization base, and a reduction in future development costs as certain undeveloped reserves have been dropped from the amortization base as a result of being uneconomic in the current price environment.
General and administrative expenses ("G&A")
Three months ended June 30, Increase/ Percent
(in thousands) 2020 2019 (Decrease) Change
G&A:
Gross G&A expenses $ 10,187 $ 9,836 $ 351 3.6 %
Capitalized exploration and
development costs (699) (2,521) 1,822 (72.3) %
Net G&A expenses 9,488 7,315 2,173 29.7 %
Net G&A expense per Boe $ 5.62 $ 2.84 $ 2.78 97.9 %
Six months ended June 30, Increase/ Percent
(in thousands) 2020 2019 (Decrease) Change
G&A:
Gross G&A expenses $ 20,480 $ 20,871 $ (391) (1.9) %
Capitalized exploration and
development costs (2,924) (5,243) 2,319 (44.2) %
Net G&A expenses 17,556 15,628 1,928 12.3 %
Net G&A expense per Boe $ 3.92 $ 3.51 $ 0.41 11.7 %
Net G&A for the three months ended June 30, 2020 , increased from the prior year
quarter primarily due to credit losses, severance for terminated employees,
sales tax interest and penalties, partially offset by a decrease in payroll and
benefits and stock compensation expense. Payroll and benefits were lower as a
result of a reduction in headcount. Stock compensation expense was lower because
our executive stock grants awarded prior to August 2019 were front loaded for
three-year periods and subject to accelerated cost recognition which results in
higher expense early during the life of a grant with graded vesting. In
addition, stock compensation expense was also lower due to recent forfeitures.
Our credit losses were recorded as we increased our allowance for uncollectible
receivables pursuant to new accounting guidance that requires us to forecast
uncollectible amounts under an "expected loss" model as well as in consideration
of current industry conditions that have been adversely impacted by COVID-19. We
incurred interest and penalties due to a nonpayment of sales tax in connection
with the divestiture of our enhanced oil recovery business in 2017.
Net G&A for the six months ended
47
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Capitalized G&A for the three and six months ended June 30, 2020 , was lower than
the prior year periods as we reduced our capitalization rates to reflect our
reduction of capital activity in response to the current price environment.
The table below discloses amounts related to the items discussed above.
Six months ended June
Three months ended June 30, 30,
(in thousands) 2020 2019 2020 2019
Employee severance costs $ 901 $ - $ 1,634 $ 1,058
Stock compensation, gross 108 1,228 768 2,647
Sales tax interest and penalties 777 - 777 -
Credit losses on receivables 1,447 (18) 2,964 (276)
$ 3,233 $ 1,210 $ 6,143 $ 3,429
Full-cost ceiling impairment
Energy commodity prices are volatile and a decline in commodity prices
negatively impacts our revenues, profitability, cash flows, liquidity (including
our borrowing base availability), and reserves, which could lead us to consider
reductions in our capital program, asset sales or organizational changes. Prices
we receive are determined by prevailing market conditions, regional and
worldwide economic and geopolitical activity, supply versus demand, weather,
seasonality and other factors that influence market conditions and often result
in significant volatility in commodity prices. We mitigate the effects of
volatility in commodity prices primarily by hedging a portion of our expected
production when permitted, focusing on a competitive cost structure and
maintaining flexibility in our capital investment program with limited long-term
commitments.
Price volatility also impacts our business through the 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 on the balance sheet date. Since the
prices used in the cost ceiling are based on a trailing 12-month period, the
full impact of price changes on our financial statements may not be recognized
immediately but could be spread over several reporting periods.
Six months ended June
Three months ended June 30, 30,
(in thousands) 2020 2019 2020 2019
Ceiling impairment $ 384,639 $ 63,593 $ 456,010 $ 113,315
We recorded a ceiling test impairment on our oil and natural gas properties for
the three months ended June 30, 2020 , due to a write-off of the value of
non-producing acreage in Garfield and Kingfisher counties, in Oklahoma , and a
decrease in the prices of all commodities used to estimate our reserves. Our
ceiling test impairment for the six months ended June 30, 2020 , was driven
largely by the same factors.
The commodity prices used to estimate our reserves are as follows:
June 30 , March
31,
Benchmark prices utilized in ceiling test 2020 2020 2019
Oil (per Bbl) $ 47.17 $ 55.77 $ 55.69
Natural gas (per MMBtu) $ 2.07 $ 2.30 $ 2.58
Natural gas liquids (per Bbl) $ 11.29 $ 14.97 $ 16.21
As discussed above, our ceiling test impairment during the second quarter of
2020 was impacted by the write-off of the value of non-producing acreage in
Garfield and Kingfisher counties, Oklahoma , that we no longer intend to develop
as a result of poor drilling economics based on our outlook on long term
commodity pricing and historical well performance. Impairments of leasehold
result in a transfer of amounts from unevaluated oil and natural gas properties
to the full cost amortization base subsequently impacting the ceiling test.
During the three and six month periods ending June 30, 2020 , impairments of
non-producing leasehold, which include expirations, were $216.2 million and
$218.7 million , respectively.
48
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The precipitous crude oil price decline caused by COVD-19 has resulted in a
first of the month price in April and May 2020 of $20.31 /Bbl and $19.78 /Bbl,
respectively with a modest recovery to $40.83 /Bbl in August 2020 . If commodity
prices remain at their current level, decline, or do not recover to a level
above $47.00 /Bbl, we expect the trailing 12-month average price to decline as
2020 progresses and we believe that it is probable that we would record further
ceiling test impairment losses in 2020. In addition to commodity prices, our
production rates, levels of proved reserves, estimated future operating
expenses, estimated future development costs, transfers of unevaluated
properties and other factors will determine our actual ceiling test calculation
and impairment analyses in future periods. Please see "Note 1: Nature of
operations and summary of significant accounting policies and going concern" in
"Item 1. Financial Statements" of this report for further discussion of our
ceiling test.
Income taxes
We did not record any net deferred tax benefit for the three and six months endedJune 30, 2020 , as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured. Please see "Note 12: Income Taxes" in "Item 8. Financial Statement and Supplementary Data" of our Annual Report on Form 10-K for the year endedDecember 31, 2019 , which contains additional information about our income taxes. As a result of the Prior Reorganization Plan and related transactions, upon emergence from bankruptcy, we experienced an ownership change within the meaning of Internal Revenue Code ("IRC") Section 382 which subjected certain of the Company's tax attributes, including our federal net operating loss carryforwards, to an IRC Section 382 limitation. If we were to experience an additional "ownership change," our ability to offset taxable income arising after the ownership change with net operating losses ("NOLs") generated prior to the ownership change would be limited, possibly substantially. See "Note 1: Nature of operations and summary of significant accounting policies and going concern" in "Item 1. Financial Statements" of this report for our discussion of the Section 382 limitation. Other income and expenses Interest expense. The following table presents interest expense for the periods indicated: Six months ended June Three months ended June 30, 30, (in thousands) 2020 2019 2020 2019 Credit facility$ 2,224 $ 838 $ 3,613 $ 988 Senior Notes 6,562 6,562 13,125 13,125 Bank fees, other interest and amortization of issuance costs 843 1,292 1,845 2,635 Interest expense, gross 9,629 8,692 18,583 16,748 Capitalized interest (1,582) (3,121) (3,900) (6,613) Total interest expense$ 8,047 $ 5,571 $ 14,683 $ 10,135 Average borrowings$ 539,012 $ 391,405 $ 492,926 $ 362,557 Interest expense for the three and six months endedJune 30, 2020 , was higher than the prior year quarter due to both an increase in gross interest expense as well as a reduction in capitalized interest. Gross interest was higher due to increased borrowings on our credit facility as reflected in the average borrowings disclosed in the table above. We capitalize interest based on the carrying value of our unevaluated non-producing leasehold excluding any amounts that are the result of our fresh start fair value adjustment. Capitalized interest for the three months endedJune 30, 2020 , was lower than the prior year period due to a lower average carrying balance on unevaluated non-producing leasehold, for which a large portion was written off recently. Reorganization items. Reorganization items reflect, where applicable, expenses, gains and losses incurred that are incremental and a direct result of the reorganization of the business resulting from the Prior Chapter 11 Cases and Prior Reorganization Plan. The reorganization items disclosed in our consolidated statement of operations consist of professional fees for continuing legal work to resolve outstanding claims and fees to theU.S. Bankruptcy Trustee, which we will continue to incur until both the Prior Chapter 11 Cases and the Chapter 11 Cases are closed. Liability management expenses. Liability management expense includes third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our Chapter 11 Cases. 49 -------------------------------------------------------------------------------- Litigation loss. The expense consists of our estimate of the settlement costs for the Naylor Farms Case as discussed (and defined) in "Note 10: Commitments and Contingencies" in "Item 1. Financial Statements" of this report. Subleases expenses. The expense consisted of our expense on operating leases for CO2 compressors that we subleased to another operator. Both originating leases and subleases were terminated during the third quarter of 2019. Write off Senior Note issuance costs. Our filing of the Chapter 11 Cases triggered an event of default on our Senior Notes. The event of default effectively allows the lender to demand immediate repayment, thus shortening the life of our Senior Notes to the current period. As a result, we wrote off the remaining balance of unamortized issuance costs.
Non-GAAP financial measure and reconciliation
Management uses adjusted EBITDA (as defined below) as a supplemental financial
measurement to evaluate our operational trends. Items excluded generally
represent non-cash and/or non-recurring adjustments, the timing and amount of
which cannot be reasonably estimated and are not considered by management when
measuring our overall operating performance. In addition, Adjusted EBITDA is
generally consistent with the EBITDAX calculation that is used in the Ratio of
Total Debt to EBITDAX covenant under our credit facility. We consider compliance
with this covenant to be material.
Adjusted EBITDA is used as a supplemental financial measurement in the
evaluation of our business and should not be considered as an alternative to net
income, as an indicator of our operating performance, as an alternative to cash
flows from operating activities, or as a measure of liquidity. Adjusted EBITDA
is not defined under generally accepted accounting principles ("GAAP") and,
accordingly, it may not be a comparable measurement to those used by other
companies.
We define adjusted EBITDA as net income, adjusted to exclude (1) asset
impairments, (2) interest and other financing costs, net of capitalized
interest, (3) income taxes, (4) depreciation, depletion and amortization, (5)
non-cash change in fair value of non-hedge derivative instruments, (6) interest
income, (7) stock-based compensation expense, (8) gain or loss on disposed
assets, (9) impairment charges, (10) other significant, unusual non-cash charges
and (11) certain expenses related to our restructuring, cost reduction
initiatives, reorganization, severance costs and fresh start accounting
activities, some or all of which our lenders have permitted us to exclude when
calculating covenant compliance.
The following tables provide a reconciliation of net loss to adjusted EBITDA for
the specified periods:
Six months ended June
Three months ended June 30, 30,
(in thousands) 2020 2019 2020 2019
Net loss (438,726)
(45,229)
8,047 5,571 14,683 10,135
Depreciation, depletion, and
amortization 14,821 30,282 37,833 53,997
Non-cash change in fair value of
derivative instruments 35,934 (17,596) (33,272) 33,935
Impact of derivative repricing 702 - 1,404 -
Interest income - (2) - (2)
Stock-based compensation expense 90 852 496 1,654
Loss (gain) on sale of assets 261 (491) 159 (490)
Loss on impairment of oil and gas
assets 384,639 63,593 456,010 113,315
Loss on impairment of other assets 310 6,407 463 6,407
Credit loss on uncollectible
receivables 1,447 (18) 2,964 (276)
Write-off of Senior Note issuance
costs 4,420 - 4,420 -
Restructuring, reorganization and
other 1,337 313 2,654 1,833
Adjusted EBITDA $ 13,282 $ 43,682 $ 54,005 $ 71,739
Our credit facility requires us to maintain a current ratio (as defined in
Credit Agreement) of not less than 1.0 to 1.0. The definition of current assets
and current liabilities used for determination of the current ratio computed for
loan compliance purposes differs from current assets and current liabilities
determined in compliance with GAAP. Since compliance with financial covenants is
a material
50
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requirement under our Credit Agreement, we consider the current ratio calculated
under our Credit Agreement to be a useful measure of our liquidity because it
includes the funds available to us under our Credit Agreement and is not
affected by the volatility in working capital caused by changes in the fair
value of derivatives. The following table discloses the current ratio for our
loan compliance compared to the ratio calculated per GAAP:
(dollars in thousands) June 30, 2020 December 31, 2019
Current assets per GAAP $ 116,806 $ 80,390
Plus-Availability under Credit Agreement -
194,406
Less-Short term derivative instruments (15,197) (947) Current assets as adjusted$ 101,609 $ 273,849 Current liabilities per GAAP 588,165 122,669 Less-Current derivative instruments -
(11,957)
Less-Current operating lease obligation (1,331)
(1,259)
Less-Current asset retirement obligation (2,107)
(2,083)
Less-Current maturities of long term debt (521,292)
(594)
Current liabilities as adjusted$ 63,435 $
106,776
Current ratio per GAAP 0.20
0.66
Current ratio for loan compliance 1.60
2.56
Off-Balance Sheet Arrangements
At
Critical accounting policies
For a discussion of our critical accounting policies, see "Management's
Discussion and Analysis of Financial Condition and Results of Operations" in our
Annual Report on Form 10-K for the year ended
Also see the footnote disclosures included in "Note 1: Nature of operations and summary of significant accounting policies and going concern" in "Item 1. Financial Statements" of this report. Recent accounting pronouncements
See recently adopted and issued accounting standards in "Note 1: Nature of operations and summary of significant accounting policies and going concern" in "Item 1. Financial Statements" of this report.
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