Riley Exploration Permian, Inc. 10-Q

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of the Company’s financial condition and results of operations should be read in conjunction with the Company’s unaudited condensed consolidated financial statements and related notes thereto presented in this report as well as the Company’s audited consolidated financial statements and related notes included in the Company's current report on Form 8-K/A filed on April 22, 2021. The following discussion contains “forward-looking statements” that reflect the Company’s future plans, estimates, beliefs and expected performance. The Company’s actual results could differ materially from those discussed in these forward-looking statements. See "Cautionary Statements Regarding Forward-Looking Statements", “—Forward-Looking Statements and Risk” and “Part II. Item 1A. Risk Factors” . Overview We operate in the upstream segment of the oil and gas industry and are focused on steadily growing conventional reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas and natural gas liquids (“NGLs”) primarily in the Permian Basin. The Company’s activities are primarily focused on the San Andres Formation, a shelf margin deposit on the Central Basin Platform and Northwest Shelf. Financial and Operating Highlights Financial and operating results reflect the following: • Completed Merger on February 26, 2021 • Increased total equivalent production by 11% to 8.3 MBoe/d for the three months ended March 31, 2021, as compared to the same period in 2020, despite significant reductions in capital expenditures and production outages due to two severe storms • Realized average composite price on commodities of $49.12 per Boe during the second quarter of 2021, representing a 37% increase over the same period in 2020 • Realized average composite price on commodities of $42.68 per Boe, including derivative settlements, during the second quarter of 2021, representing a 3% decrease over the same period in 2020 • Generated cash flow from operations of $38.1 million for the six months ended March 31, 2021 • Incurred total capital expenditures of $17.1 million primarily related to oil and natural gas drilling and completion activity for the six months ended March 31, 2021, representing a significant decrease of 49% compared to the same period for 2020 • Paid cash common dividends of $3.8 million during the three months ended March 31, 2021; announced latest dividend of $0.28 per share with a record date of April 16, 2021, which was paid May 7, 2021, for a total of $5.0 million • Exited the second quarter with $10.1 million in cash and $97.5 million drawn on our credit facility Recent Developments Market Conditions and Commodity Prices The COVID-19 pandemic and the measures being taken to address and limit the spread of the virus significantly reduced global economic activity, resulting in a significant decline in the demand for and prices of crude oil and condensate, natural gas liquids (NGLs) and natural gas. Additionally, production disagreements among members of the Organization of Petroleum Exporting Countries and certain other oil exporting countries (OPEC+), led to significantly lower commodity prices during March and April 2020, including historically low oil prices. Subsequently, members of OPEC+ reached agreements to limit oil production with phased returns of production over time. Questions over individual member compliance with such agreements, as well as the duration and potential extensions of such production cuts, has led to uncertainty over supply and demand balances. These factors caused a swift and material deterioration in commodity prices for a majority of 2020. 36 The Company cannot estimate the full length or gravity of the future impacts at this time and if there is another significant decline in oil price, it could have a material adverse effect on the Company’s results of operations, financial position, liquidity and the value of oil and natural gas reserves. The Company has developed and implemented a number of safety measures, which have successfully kept our workforce healthy and safe. The Company has established an informational campaign to provide employees an understanding of the virus risk factors and safety measures, as well as timely updates from governmental stay-at-home regulations. Expectations have also been set for employees to communicate immediately if they, or someone they have been in contact with, has experienced symptoms or tested positive for COVID-19. Additional measures include distribution of education material regarding health and safety guidance, limiting access to common areas within the office, ensuring social distancing guidance by relocating personnel, and other guidelines as recommended by the Center for Disease Control and Prevention (CDC) and local authorities. In response to the 2020 market conditions described above, and in an effort to preserve liquidity, the Company updated its 2020 capital and operating plan to significantly reduce drilling and completion activity and decrease its capital expenditures. Additionally, the Company quickly made significant cuts in G&A with reductions in workforce, information technology, and professional fees. The Company further preserved liquidity by reducing cash dividends on common units by 50%. On December 15, 2020 our gas gatherer and processor in Yoakum County, TX, Stakeholder Midstream announced that it had acquired Santa Fe Midstream's Gas Gathering and Processing Assets (the "Santa Fe Assets") located in Yoakum County. Shortly thereafter they began to integrate the newly acquired assets with their Campo Viejo Processing Plant and gathering system. When completed in early February 2021, this integration allowed Riley Permian to commence selling incremental volumes of natural gas and natural gas liquids that were previously being flared. Further, the increase in natural gas and natural gas liquids as a percentage of our production stream is a direct result of additional gas gathering and processing capabilities, and does not represent a change in the gas oil ratio ("GOR"). Increase in natural gas and natural gas liquids deliveries 30% and 39%, respectively, or 52.5 MBoe first quarter to second quarter. In February 2021, Winter Storm Uri was a major coast-to-coast storm that produced snow and damaging ice from the Northwest into the South, Midwest and interior Northeast which significantly increased demand for natural gas from record low temperatures across the United States. The state of Texas experienced record snow levels and experienced the coldest temperatures in decades for certain cities. These conditions resulted in challenges to the producing wells in Texas by causing freeze-offs (temporary interruptions in production caused by cold weather). The freeze-offs coupled with increased national demand caused significant increases in natural gas spot prices. As a result of Winter Storm Uri, the Company experienced production outages which resulted in an estimated reduction of 18 net MBoe (or an average of 3.7 MBoe/d per day) over a 5-day period in February 2021. Recent Transactions On the Closing Date, Riley Permian consummated the previously announced merger pursuant to that certain Merger Agreement, dated as of October 21, 2020, by and among Tengasco, Merger Sub, and REP LLC, as amended by Amendment No. 1 to Agreement and Plan of Merger, dated as of January 20, 2021, by and among Tengasco, Merger Sub and REP, LLC. Pursuant to the terms of the Merger Agreement, a business combination between the Registrant and REP LLC was effected through the merger of Merger Sub with and into REP LLC, with REP LLC surviving as the surviving company and as a wholly-owned subsidiary of the Registrant (collectively, with the other transactions described in the Merger Agreement, the “Merger”). On the Closing Date, the Registrant changed its name from Tengasco, Inc. to Riley Exploration Permian, Inc. Our organizational structure includes wholly-owned consolidated subsidiaries through which our operations are conducted, including without limitation, REP, LLC and Riley Permian Operating Company, LLC. Immediately following the closing of the Merger, the former members of REP LLC owned 95% of the Company and the former Tengasco stockholders owned the remaining 5% of the Company. On March 10, 2021, the Company entered into a PSA to sell the Kansas Reporting Unit for an agreed upon purchase price of $3.5 million (subject to certain adjustments), contingent upon certain conditions to closing. The effective date of the sale was March 1, 2021 and the sale closed on April 2, 2021 for the agreed upon purchase price, plus approximately $0.2 million of net closing adjustments. As of March 31, 2021, the assets and liabilities associated with these divested assets were classified as held for sale in the accompanying condensed consolidated balance sheet. 37 2021 Capital and Operating Plan We expect our fiscal 2021 capital budget to be approximately $54 million to $56 million, which we believe is consistent with our capital allocation framework, and which we believe will be funded entirely by operating cash flow. 38 Comparison for the Three and Six Months Ended March 31, 2021 and 2020 The following table provides a summary of the Company’s sales volumes, average prices and certain operating expenses on a per BOE basis: 39 Three Months Ended March 31, Six Months Ended March 31, 2021 2020 2021 2020 Total Sales Volumes: Oil (MBbls) 543 554 1,090 1,077 Natural Gas (MMcf) 602 383 1,063 762 NGL (MBbls) 103 62 177 119 Total (MBoe) 1 746 680 1,445 1,323 Average Daily Sales Volumes: Oil sales (Bbl/d) 6,031 6,086 5,988 5,884 Natural gas sales (Mcf/d) 6,683 4,214 5,841 4,166 Natural gas liquids sales (Bbl/d) 1,148 681 975 653 Total (BOE/d) 1 8,293 7,469 7,937 7,231 Average Sales Price 1 : Oil sales (per Bbl) $ 56.71 $ 44.42 $ 48.53 $ 49.59 Oil sales with derivative settlements (per Bbl) 2 51.70 53.33 50.78 54.69 Natural gas sales (per Mcf) 7.51 (0.24) 4.36 (0.36) Natural gas sales with derivative settlements (per Mcf) 2 7.72 (0.24) 4.48 (0.36) Natural gas liquids sales (per Bbl) 13.16 (2.41) 8.72 (2.26) Natural gas liquids with derivative settlements (per Bbl) 2 13.16 (2.41) 8.72 (2.26) Average price per BOE 1,2 49.12 35.84 40.89 39.94 Average price per BOE including derivative settlements 1,2 45.64 43.10 42.68 44.09 Expenses per BOE 1 : Lease operating expenses $ 9.07 $ 8.87 $ 8.01 $ 8.89 Production taxes 2.60 1.70 2.08 1.90 Exploration expenses 7.33 2.57 4.08 1.87 Depletion, depreciation, amortization, and accretion 8.38 7.88 8.47 8.31 General and administrative expenses 10.11 5.47 7.20 5.36 General and administrative expenses, net of gross profit on contract services 3 9.42 4.13 6.54 4.00 Transaction costs 2.90 0.04 2.22 0.02 1 One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on the approximate energy equivalency. This is an energy content correlation and does not reflect value or price relationship between the commodities. 2 Average prices shown in table reflect prices both before and after the effects of REXP’s settlements of our commodity derivative contracts. REXP’s calculation of such effects includes both gains or losses on cash settlements for commodity derivatives. The impact of these cash settlements are included in other income and expense on the Company’s Statement of Operations. 3 General and administrative expenses shown after the effect of gross profit from contract services derived from management services agreements. 40 Oil and Natural Gas Revenues The Company’s total oil and natural gas revenue, net increased 51% and 12% for the three and six months ended March 31, 2021, respectively, as compared to total oil and natural gas revenues for the same period of 2020. This increase for the three and six month periods was driven by a combination of higher composite price and higher equivalent volume. The Company’s oil and natural gas sales, net in its financial statements do not include the effects of derivatives as those effects are included within other income. The Company’s realized average composite price on commodities of $49.12 per Boe for the second quarter of 2021 increased by $13.28 per Boe, or 37%, over the realized average composite price of $35.84 per Boe for the same period of 2020. The Company’s realized average composite price on commodities of $40.89 per Boe, for the first six months of 2021 increased by $0.95 per Boe, or 2%, over the realized average composite price of $39.94 per Boe for the same period of 2020. The Company's realized price increased across all commodities, which was driven by a general improvement in supply/demand fundamentals over the same period of 2020, as well as short-term, significant price increases experienced during Winter Storm Uri. The Company’s average daily production increased by 11% and 10% to 8.3 MBoe per day and 7.9 MBoe per day for the three and six months ended March 31, 2021, respectively, from 7.5 MBoe per day and 7.2 MBoe per day for the same periods in 2020. Oil revenues for the second quarter of 2021 increased $6.2 million, or 25%, to $30.8 million from $24.6 million for the same period in 2020. The increase was due to a 27% increase in realized price partially offset by a decrease of 11 MBbls or 2% in production volume. Including derivative settlements, the average realized price decreased by $1.63 per Bbl or 3%. The decrease in total production was partially attributable to there being one less day in the first quarter of 2021 as compared to the same quarter of 2020 (which was a leap year); average daily production decreased by less than 1% or 55 Bbls per day in the second quarter 2021 compared to the same period in 2020. Further, the Company significantly reduced drilling and completion activity during the second quarter of 2021 as compared to the same period in 2020, including a 40% decrease in capital expenditures. Finally, the Company experienced production outages during two severe storms. Production outages experienced during Winter Storm Uri resulted in a reduction of 14.6 net MBbls (or an average of 2.9 MBbls per day) over a 5-day period in February 2021. Revenues derived from the sale of natural gas and natural gas liquids for the second quarter of 2021 increased by a combined $6.1 million to $5.9 million from negative $0.2 million for the same period in 2020. Revenues derived from the sale of natural gas and natural gas liquids for the first six months of 2021 increased by a combined $6.7 million to $6.2 million from negative $0.5 million for the same period in 2020. These increases were driven by a combination of significantly higher prices and volume. Higher prices for both natural gas and natural gas liquids were driven by a general improvement in supply/demand fundamentals over the same period in 2020, as well as short-term, significant price increases experienced during Winter Storm Uri. The Company’s natural gas and natural gas liquids sales volumes increased for the second quarter of 2021 by 219 MMcf (57% increase over second quarter 2020) and 41 MBbls (66% increase over second quarter 2020), respectively, to 602 MMcf and 103 MBbls, respectively. The Company’s natural gas and natural gas liquids sales volumes increased for the first six months of 2021 by 301 MMcf (40% increase over first six months of 2020) and 58 MBbls (49% increase over first six months of 2020), respectively, to 1,063 MMcf and 177 MBbls, respectively. The increased production volume in both natural gas and natural gas liquids volumes were attributable primarily to a significant increase in gas processing capacity available from the Company’s midstream gathering and processing partner, Stakeholder Midstream, as a result of the acquisition of an additional gas processing plant by Stakeholder Midstream. The increase in natural gas and natural gas liquids as a percentage of the Company's total equivalent production is a direct result of additional gas gathering and processing capabilities, and does not represent a change in the GOR. 41 The following tables present oil and natural gas revenues disaggregated by product: March 31, 2021 March 31, 2020 Change % Change ($ in thousands) Three Months Ended Oil sales $ 30,784 $ 24,598 $ 6,186 25 % Natural gas sales 4,516 (93) 4,609 4,956 % Natural gas liquids sales 1,359 (149) 1,508 1,012 % Oil and natural gas sales, net $ 36,659 $ 24,356 $ 12,303 51 % Six Months Ended Oil sales $ 52,891 $ 53,396 $ (505) (1) % Natural gas sales 4,635 (271) 4,906 1,810 % Natural gas liquids sales 1,547 (270) 1,817 673 % Oil and natural gas sales, net $ 59,073 $ 52,855 $ 6,218 12 % The following tables present sales volumes for the Company’s continuing operations: March 31, 2021 March 31, 2020 Change % Change ($ in thousands) Three Months Ended: Oil (MBbls) 543 554 (11) (2) % Natural gas (MMcf) 602 383 219 57 % Natural gas liquids (MBbls) 103 62 41 66 % Total (MBoe) 4 746 680 66 10 % Average net sales (BOE/d) 4,5 8.3 7.5 0.8 11 % Six Months Ended: Oil (MBbls) 1,090 1,077 13 1 % Natural gas (MMcf) 1,063 762 301 40 % Natural gas liquids (MBbls) 177 119 58 49 % Total (MBoe) 4 1,445 1,323 122 9 % Average net sales (BOE/d) 4,5 7.9 7.2 0.7 10 % 4 One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on the approximate energy equivalency. This is an energy content correlation and does not reflect value or price relationship between the commodities. 5 Average net sales (BOE/d) was derived by dividing the total MBoe by 91 days and 90 days for the three months ended March 2021 and 2020, respectively. Average net sales (BOE/d) was derived by dividing the total MBoe by 182 days and 181 days for the six months ended March 2021 and 2020, respectively. 42 Realized Prices on Oil and Natural Gas Sales The following table presents the Company’s average realized commodity prices, as well as the effects of derivative settlements: Three Months Ended March 31, Six Months Ended March 31, 2021 2020 2021 2020 ($ in thousands) Oil NYMEX WTI Average ($/Bbl) $ 57.84 $ 46.17 $ 50.25 $ 51.57 Differential ($/Bbl) to Average NYMEX WTI 1.13 1.75 1.72 1.98 Average Realized Price ($/Bbl) 56.71 44.42 48.53 49.59 Averaged Realized Price as a % of Average NYMEX WTI 6 98 % 96 % 97 % 96 % Average Realized Price, with derivative settlements ($/Bbl) 51.70 53.33 50.78 54.69 Natural Gas 7 NYMEX Henry Hub Average ($/MMBtu) $ 2.69 $ 1.95 $ 2.68 $ 2.23 Differential ($/Mcf) to Average NYMEX Henry Hub 6 (4.82) 2.19 (1.68) 2.59 Average Realized Price ($/Mcf) 7.51 (0.24) 4.36 (0.36) Averaged Realized Price as a % of Average NYMEX Henry Hub 279 % (12) % 163 % (16) % Average Realized Price, with derivative settlements ($/Mcf) 7.72 (0.24) 4.48 (0.36) Natural Gas Liquids 7 Average Realized Price ($/Bbl) $ 13.16 $ (2.41) $ 8.72 $ (2.26) Averaged Realized Price as a % of Average NYMEX WTI 23 % (5) % 17 % (4) % BOE (Barrel of Oil Equivalent) Average price per BOE 6 $ 49.12 $ 35.84 $ 40.89 $ 39.94 Average price per BOE with derivative settlements 6,8 45.64 43.10 42.68 44.09 While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within the Company’s industry, the prices the Company receives are affected by quality, energy content, location and transportation differentials for these products. 6 One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on the approximate energy equivalency. This is an energy content correlation and does not reflect value or price relationship between the commodities. 7 Realized prices are reflected at net of the deduction of gathering, processing and transportation costs. 8 Average prices shown in table reflect prices both before and after the effects of our settlements of REP’s commodity derivative contracts. REP’s calculation of such effects includes both gains or losses on cash settlements for commodity derivatives. 43 Contract Services - Related Party Revenue The following tables present the Company's gross profit for related party transactions: Three Months Ended March 31, Six Months Ended March 31, 2021 2020 2021 2020 ($ in thousands) Contract services – related parties $ 600 $ 1,050 $ 1,200 $ 2,100 Cost of contract services - related parties 91 138 239 306 Gross profit - related parties $ 509 $ 912 $ 961 $ 1,794 Gross profit percentage - related parties 85 % 87 % 80 % 85 % The Company’s contract services – related parties revenue is derived from master services agreements with related parties to provide certain administrative support services. See Note 9 – Transactions with Related Parties to the Company's unaudited condensed consolidated financial statement included herein for more information. The Company's contract services - related parties gross profit decreased for the three and six months ended March 31, 2021 primarily due to the restructuring of the monthly fee in the fourth quarter of fiscal 2020. The monthly fee decreased by $150 thousand per month. Lease Operating Expenses The Company’s lease operating expenses ("LOE") increased by 12%, or $0.8 million, to $6.8 million or $9.07 per Boe for the three months ended March 31, 2021, from $6.0 million or $8.87 per Boe for the three months ended March 31, 2020. The net increase in LOE when compared to the three months ended March 31, 2020 is attributable to a combination of factors, including an increase of $0.6 million due to higher equivalent production, an increase of $0.4 million related to ad valorem taxes, an increase of $1.0 million related to a non-recurring workover expense, and a decrease of $1.2 million due to general performance improvement of recurring LOE. The Company’s non-recurring workover expense was related to a downhole failure on a salt-water disposal well, which led to an increase in LOE of 21% or approximately $1.34 per Boe. Excluding this non-recurring workover, LOE for the three months ended March 31, 2021 would have been lower than the same period in 2020 by $1.38 per Boe, or 16%, at an estimated $7.49 per Boe. Production Tax Expense Production taxes increased to $1.9 million and $3.0 million for the three and six months ended March 31, 2021, respectively, due to increases in commodity sales. On a per unit basis, production taxes increased by $0.90 per Boe or 53% to $2.60 per Boe for the second quarter 2021 from $1.70 per Boe for the same period in 2020. This increase was driven by the significantly higher commodity prices realized in the second quarter of 2021, including the short-term high prices of natural gas and natural gas liquids attributable to Winter Storm Uri. Exploration Expense Exploration expense increased to $5.5 million and $5.9 million, respectively, for the three and six months ended March 31, 2021. On a per unit basis, exploration expense increased by $4.76 per Boe to $7.33 per Boe for the three months ending March 31, 2021, from $2.57 per Boe for the same period in 2020; exploration expense increased by $2.21 per Boe to $4.08 per Boe for the six months ending March 31, 2021, from $1.87 per Boe for the same period in 2020. This increase was driven by lease expirations of in the Champions and Montaña fields. 44 The following table summarizes exploration expense by field below: Champions Montaña Three Months Ended March 31, 2021 Exploration expense $ 2,900 $ 2,503 Expired net acres 1,368 6,296 Net acres renewed after expiration 398 — Six Months Ended March 31, 2021 Exploration expense $ 3,125 $ 2,702 Expired net acres 1,467 7,201 Net acres renewed after expiration 486 — Depletion, Depreciation, and Accretion Expense The following table disaggregates the Company's depletion, depreciation, amortization and accretion expense: Three Months Ended March 31, Six Months Ended March 31, 2021 2020 2021 2020 ($ in thousands) Oil and natural gas depletion $ 6,119 $ 5,239 $ 12,010 $ 10,730 Other property and equipment depreciation 110 105 188 209 ARO accretion 22 13 43 53 Total depletion, depreciation, and accretion expense $ 6,251 $ 5,357 $ 12,241 $ 10,992 The Company’s depletion rate and expense increased for the three and six months ended March 31, 2021 due to higher production volumes and lower estimated proved reserves as used for the depletion calculation. The decrease in reserves used in the depletion calculation was due to the lower trailing, 12-month first day of the month weighted average price as reflected on the September 30, 2020 reserve report, as compared to the same weighted-average price calculated on September 30, 2019. General and Administrative Costs The following table disaggregates general and administrative costs shown after the effect of gross profit from contract services derived from management services agreements: Three Months Ended March 31, Six Months Ended March 31, 2021 2020 2021 2020 ($ in thousands) Payroll and benefit costs $ 1,731 $ 2,217 $ 3,370 $ 4,403 Non-payroll costs 965 1,297 1,771 2,330 Unit-based compensation expense 276 206 689 359 Stock-based compensation expense 4,571 — 4,571 — Total general and administrative costs 7,543 3,720 10,401 7,092 Less: Gross profit - related party 509 912 961 1,794 G&A, net of gross profit - related party $ 7,034 $ 2,808 $ 9,440 $ 5,298 45 G&A costs increased for the three and six months ended March 31, 2021 by 103% and 47%, as compared to the same periods for 2020, respectively. On a per unit basis, G&A expense increased by $4.64 or 85% per Boe to $10.11 per Boe for the three months ending March 31, 2021, from $5.47 per Boe for the same period in 2020; G&A expense increased by $1.84 or 34% per Boe to $7.20 per Boe for the six months ending March 31, 2021, from $5.36 per Boe for the same period in 2020. The largest contributor to the increase in G&A expense was additional compensation expense of $4.2 million related to restricted shares and stock awards given to certain executives and employees as a result of the Merger for the three and six months ended March 31, 2021. This expense was in part offset by the Company taking swift action to reduce G&A expense across several categories following the dual shocks of the COVID-19 pandemic and the OPEC+ production cut disagreements. The Company took measures to reduce its workforce during 2020 which contributed to a 22% and 23% decrease in payroll and benefit costs in G&A for the three and six month periods ended March 31, 2021 compared to the same periods for 2020, respectively. Non-payroll costs decreased by 26% and 24%, for the three and six month periods ended March 31, 2021 compared to the same periods for 2020, respectively, related to reductions in costs associated with information technology, legal and consulting expenses. Transaction Costs Transaction costs were $2.2 million and $3.2 million, respectively, for the three and six months ended March 31, 2021, respectively. The transaction costs are related to the fees incurred for the Merger. See Note 4 - Business Combinations to the Company's unaudited condensed consolidated financial statements included herein for further discussion of the Merger. Interest Expense Interest expense decreased to $1.2 million and $2.4 million due to lower borrowings during the three and six months ended March 31, 2021. Income Tax Provision REP LLC became a taxable entity as a result of its Merger with Tengasco on February 26, 2021. See further discussion in Note 4 - Business Combinations. While REP LLC was organized as a limited liability company, taxable income passed through to its unit holders. Accordingly, a provision for federal and state corporate income taxes has been made only for the operations of REP LLC in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the Merger into a corporation on February 26, 2021, the Company established a $13.6 million provision for deferred income taxes, of which $1.1 million is currently payable. The majority of this deferred tax liability was established by a change in tax status which primarily was attributable to the oil and natural gas properties. Three Months Ended March 31, Six Months Ended March 31, 2021 2020 2021 2020 ($ in thousands) Current expense (benefit) $ 1,143 $ — $ 778 $ — Deferred expense (benefit) 13,088 — 12,938 — Total expense (benefit) $ 14,231 $ — $ 13,716 $ — Effective income tax rate (74.7) % — % (49.9) % — % 46 Derivative Arrangements The following table presents the Company's derivative activities. Three Months Ended March 31, Six Months Ended March 31, 2021 2020 2021 2020 ($ in thousands) Fair value of net asset (liability), beginning of period $ 2,839 $ (3,632) $ 21,921 $ 14,959 Gain (loss) on derivatives (24,903) 69,239 (38,812) 51,204 Settlements on derivatives 2,594 (4,936) (2,579) (5,492) Fair value of net asset (liability), end of period $ (19,470) $ 60,671 $ (19,470) $ 60,671 The unrealized loss for the three and six months ended March 31, 2021 is due primarily to increasing crude oil future prices resulting from the improving supply/demand balances. Whereas the realized gains during the three and six months ended March 31, 2020 was primarily derived from the significant decline in crude oil future pricing from the COVID-19 pandemic and the OPEC+ related disagreements. As commodity prices fluctuate, so will the income or loss the Company recognizes from its hedging activities. See Note 7 - Derivative Instruments to the Company's unaudited condensed consolidated financial statements included herein for more information of the Company's derivative arrangements. Liquidity and Capital Resources The Company’s primary sources of liquidity have been cash flows from operations and borrowings under the Company’s revolving credit facility. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s properties. The Company last raised equity from investors in 2017. The following table summarizes the Company’s cash flows from continuing operations: Six Months Ended March 31, 2021 2020 ($ in thousands) Statement of Cash Flows Data from Continuing Operations: Net cash provided by operating activities 38,146 36,252 Net cash used in investing activities (16,825) (37,741) Net cash (used in) provided by financing activities (13,152) 1,068 Operating Activities Our cash flows from operating activities are sensitive to a variety of variables including commodity pricing and production. The Company plans to continue its practice of entering into hedging arrangements to reduce the impact of commodity price volatility on the Company’s cash flow from operations. Under this strategy, the Company expects to maintain an active hedging program which the Company believes will provide more certainty around its cash flow and returns, ability to fund its capital program and dividends on common stock. Additionally, the Company has certain covenants under its revolving credit facility to maintain active commodity price hedges. The Company’s net cash provided by operating activities increased by $1.9 million for the six months ended March 31, 2021 as compared to the six months ended March 31, 2020, driven by an increase of $3.6 million from changes in working capital, partially offset by a $1.7 million decrease in cash flow from operating activities before working capital. Investing Activities The Company's cash flows used in investing activities decreased by $20.9 million or 55% to $16.8 million for the six months ended March 31, 2021 from $37.7 million for the same periods in 2020. The Company incurred $17.1 million of capital spending during the six months ended March 31, 2021 primarily related to drilling and completion costs, a decrease of $16.6 million, or 49%, as compared to the six months ended March 31, 2020. The Company drilled 11 gross (8.9 net) wells and completed 8 gross (5.5 net) wells during the six months ending March 31, 2021. Additionally, capital spending related to the acquisition of properties decreased by $3.8 million during the six months ended March 31, 2021 as compared 47 to the same period in 2020. Finally, the Company acquired cash of $0.9 million by way of the Tengasco transaction for the six months ended March 31, 2021, as compared to $0 acquired cash from business combinations for the same period in 2020. Financing Activities The Company's cash flows used in/provided by financing activities is influenced by the discretionary nature of our investing activities in order to line up with the Company's operating strategy. As of March 31, 2021, the Company had a revolving credit facility with a borrowing base of $135 million and outstanding borrowings of $97.5 million. Additionally, the Company has an available borrowing capacity of $37.5 million as of March 31, 2021. See “—Revolving Credit Facility” below for further discussion. For the six months ended March 31, 2021 cash used in financing activities was $13.2 million as compared to $1.1 million provided by financing activities during the six months ended March 31, 2020. The Company’s net cash used by financing activities in the six months ended March 31, 2021 was primarily related to $9.3 million cash payments of common and preferred dividends and $3.5 million net repayments of the credit facility. Working Capital The Company’s working capital, which the Company defines as current assets minus current liabilities, totaled a deficit of $29.6 million at March 31, 2021. This deficit is primarily attributable to $26.5 million of accrued liabilities and $14.3 million in current derivative liabilities. The Company may continue to incur working capital deficits in the future due to the amounts that accrue related to its drilling program and changes in the value of its derivative assets and liabilities. The Company’s collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. The Company’s cash and cash equivalents balance totaled approximately $10.1 million at March 31, 2021 and was $1.7 million at September 30, 2020, respectively. The cash balance as of March 31, 2021 was higher due to unanticipated timing of revenue collections from natural gas and natural gas liquid sales which the Company received at the end of March. The Company forecasts cash flows from operating activities, and availability under the Company’s revolving credit facility will be sufficient to fund its working capital needs through May 2022. The Company expects that its pace of development, production volumes, commodity prices and differentials to NYMEX prices for the Company’s oil and natural gas production will be the largest variables affecting the Company’s working capital. Please see “—Liquidity and Capital Resources” above for factors relating to liquidity and current expectations. Revolving Credit Facility The Company's borrowing base was $135 million with outstanding borrowings of $97.5 million at March 31, 2021. See further discussion in Note 10 — Revolving Credit Facility to the Company's unaudited condensed consolidated financial statements included herein. Critical Accounting Policies The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s unaudited condensed consolidated financial statements included herein, which have been prepared in accordance with U.S. GAAP. The preparation of financial statements requires the Company to make estimates and assumptions that affect the amounts reported in the unaudited condensed consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The unaudited condensed consolidated financial statements are based on a number of significant estimates, including estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, accounts receivable and accrued operating expenses, the fair value determination of acquired assets and liabilities, income tax provisions and the fair value of derivatives. Changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and assumptions used in preparation of the Company’s unaudited condensed consolidated financial statements and it is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. The preparation of the Company’s financial statements requires the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable 48 likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and natural gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties; (3) depreciation, depletion, amortization and accretion, or DD&A; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accounts receivable; (7) valuation of commodity derivative instruments; (8) accrued liabilities; and (9) income tax provisions. Actual results may differ from these estimates and assumptions used in preparation of the Company’s unaudited condensed consolidated financial statements included herein. Forward-Looking Statements and Risk Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company’s control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil, natural gas and NGLs, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict. There are numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can also affect these risks. Additionally, fluctuations in oil and natural gas prices, or a prolonged period of low prices, may substantially adversely affect the Company's financial position, results of operations, and cash flows. 49