# Evolution Petroleum Corp: Form 10-Q for the period ended Mar 31, 2023

- Company: [Evolution Petroleum Corp](/companies/epm.md) (CIK 1006655)
- Form: 10-Q
- Filed: 2023-05-10
- Accepted by EDGAR: May 10, 2023, 16:11 ET
- Period: 2023-03-31
- Accession: 0001558370-23-009105
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1006655/000155837023009105/epm-20230331x10q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1006655/000155837023009105/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2023-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2023-01-01 to 2023-03-31 | $36.9m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Revenue | 9 months, 2022-07-01 to 2023-03-31 | $110.3m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Cost of revenue | 3 months, 2023-01-01 to 2023-03-31 | $13.6m | us-gaap:CostOfGoodsAndServicesSold |
| Cost of revenue | 9 months, 2022-07-01 to 2023-03-31 | $47.7m | us-gaap:CostOfGoodsAndServicesSold |
| Operating income | 3 months, 2023-01-01 to 2023-03-31 | $17.6m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2022-07-01 to 2023-03-31 | $44.9m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2023-01-01 to 2023-03-31 | $32.0k | us-gaap:InterestExpense |
| Interest expense | 9 months, 2022-07-01 to 2023-03-31 | $404.0k | us-gaap:InterestExpense |
| Income tax | 3 months, 2023-01-01 to 2023-03-31 | $3.9m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2022-07-01 to 2023-03-31 | $9.9m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2023-01-01 to 2023-03-31 | $14.0m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2022-07-01 to 2023-03-31 | $35.1m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2023-01-01 to 2023-03-31 | $0.41 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2022-07-01 to 2023-03-31 | $1.04 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2023-01-01 to 2023-03-31 | $0.42 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2022-07-01 to 2023-03-31 | $1.04 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2023-01-01 to 2023-03-31 | 33,156,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2022-07-01 to 2023-03-31 | 33,291,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2022-07-01 to 2023-03-31 | $51.7m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Dividends paid | 9 months, 2022-07-01 to 2023-03-31 | $12.1m | us-gaap:PaymentsOfDividendsCommonStock |
| Share repurchases | 9 months, 2022-07-01 to 2023-03-31 | $4.0m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2023-03-31 | $18.4m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2023-03-31 | $31.0m | us-gaap:AssetsCurrent |
| Total assets | at 2023-03-31 | $137.7m | us-gaap:Assets |
| Current liabilities | at 2023-03-31 | $20.3m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2023-03-31 | $42.0m | us-gaap:Liabilities |
| Shareholders' equity | at 2023-03-31 | $95.6m | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 53,916 characters.

#### Executive Overview

#### Liquidity and Capital Resources

#### Results of Operations

#### Critical Accounting Policies

### Commonly Used Terms

*“Current quarter” refers to the three months ended March 31, 2023, our third quarter of fiscal year 2023.*

*“Year-ago quarter” refers to the three months ended March 31, 2022, our third quarter of fiscal year 2022.*

### Executive Overview

### General

Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States. In support of that objective, our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisitions and through selective development opportunities, production enhancements, and other exploitation efforts on our oil and natural gas properties.

Our oil and natural gas properties consist of non-operated interests in the following areas: the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana; as well as small overriding royalty interests in four onshore central Texas wells.

Our interests in the Jonah Field, a natural gas and natural gas liquids producing property in Sublette County, Wyoming, consist of an approximately 20% average net working interest with an associated 15% average net revenue interest in 595 producing wells and 950 net acres. The properties are operated by Jonah Energy (“Jonah”), an established operator in the region.

Our interests in the Williston Basin, producing oil and natural gas properties, consist of an approximately 39% average net working interest with an associated 33% average net revenue interest in 73 producing wells located on approximately 45,000 net acres (approximately 90% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are primarily operated by Foundation Energy Management (“Foundation”), an established operator in the region.

Our interests in the Barnett Shale, natural gas and natural gas liquids producing properties, consist of an approximately 17% average net working interest with an associated 14% average net revenue interest (inclusive of small overriding royalty interests). The approximately 21,000 net acres are held by production across nine North Texas counties. The properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by seven other operators.

Our interests in the Hamilton Dome Field, a secondary oil recovery field utilizing water injection wells to pressurize the reservoir, consist of an approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest). The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company (“Merit”), who owns the vast majority of the remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming.

Our interests in the Delhi Field, a CO2-EOR project, consist of approximately 24% average net working interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC (“Denbury”). The Delhi Field is located in northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses approximately 14,000 gross unitized acres, or approximately 3,200 net acres.

### Recent Developments

### Senior Secured Credit Facility

On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among other things, extends the maturity of our Senior Secured Credit Facility to April 9, 2026, converts our benchmark interest rate from London Interbank Offered Rate (LIBOR) to a Secured Overnight Financing Rate (SOFR) plus a credit spread adjustment of 0.05%, and modifies the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million.

### Appointment of Chief Operating Officer

On February 23, 2023, we announced that the Board of Directors appointed J. Mark Bunch as Chief Operating Officer (“COO”). Mr. Bunch had been providing consulting services to the Company since 2016. We entered into an offer letter with Mr. Bunch setting forth his compensation as COO on February 21, 2023.

### Appointment of Chief Executive Officer

On October 27, 2022, we announced that the Board of Directors selected Kelly W. Loyd as President and Chief Executive Officer (“CEO”). Mr. Loyd had been serving as Interim CEO since June 2022 and has served as a member of the Board of Directors since 2008. We entered into an offer letter with Mr. Loyd setting forth his compensation as CEO on October 25, 2022. Upon commencing employment, Mr. Loyd no longer receives compensation for his services as a member of the Board of Directors.

### Share Repurchase Program

On September 8, 2022, the Board of Directors approved a share repurchase program under which we are authorized to repurchase up to $25.0 million of our common stock through December 31, 2024. We intend to fund repurchases from available working capital and cash provided by operating activities. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors and management team believe that a share repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of our shares, the market price of our common stock, our capital needs and resources, general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice.

Once we completed repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout period in December 2022, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan is effective until June 30, 2023, unless extended or renewed, and has a maximum authorized amount of $5.0 million over that period. We may alter the terms of the plan from time to time to the extent we determine changes are necessary to achieve the intended objectives of the repurchase program. During the three months ended March 31, 2023, 0.6 million shares of our common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.

### Highlights and Operations Update

- Generated revenue of $36.9 million and net income of $14.0 million.
- Production averaged 7,089 net barrels of oil equivalent per day (“BOEPD”).
- Returned to shareholders $12.1 million in cash dividends during the nine months ended March 31, 2023 while repaying $21.3 million of borrowings on our Senior Secured Credit Facility incurred in calendar 2022 to acquire our Williston Basin and Jonah Field properties. We have paid out to shareholders more than $98.4 million in cash dividends since inception of the dividend program in December 2013.
- Purchased 0.6 million shares of common stock for approximately $3.9 million under our repurchase program.
- Continued to fund all operations, development capital expenditures, dividends and repurchase of shares out of operating cash flow.
- Ended the third quarter of fiscal 2023 with $18.4 million in cash and cash equivalents and no outstanding borrowings under our Senior Secured Credit Facility.

### Risks and uncertainties

The global economy was deeply impacted by the effects of the novel coronavirus (“COVID-19”) pandemic and related efforts to mitigate the spread of the disease. These events led to crude oil prices falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020.

Beginning in 2021, the demand for oil and natural gas started to recover primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses. In addition, the military activities of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which further enhanced volatility in global commodity prices in the first half of 2022.

Additionally, during the quarter ended March 31, 2023, the closures of Silicon Valley Bank and Signature Bank and their placement into receivership with the Federal Deposit Insurance Corporation (FDIC) created broad uncertainty around world-wide financial institutions and liquidity risk. While we do not have exposure to these banks, we do maintain cash balances in excess of FDIC insurance protections at banks we believe to be financially sound. We also utilize insured cash sweep deposits to maximize the amount of our cash that is protected by FDIC insurance.

We also rely heavily on our third-party operators who manage their own liquidity with various financial institutions.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist; predict the broader impact of liquidity concerns around financial institutions; or the impact on the commodity prices that we realize.

Currently, our oil and natural gas properties are operated by third-party operators and involve other third-party working interest owners. As a result, we have limited ability to influence the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review capital expenditures and present alternative plans as necessary.

### Liquidity and Capital Resources

As of March 31, 2023, we had no borrowings outstanding on our Senior Secured Credit Facility and $18.4 million in cash and cash equivalents compared to $21.3 million of borrowings drawn on our Senior Secured Credit Facility and $8.3 million in cash and cash equivalents at June 30, 2022. Our primary sources of liquidity and capital resources during the nine months ended March 31, 2023 were cash provided by operations and the unused portion of our credit facility. Our primary uses of liquidity and capital resources for the nine months ended March 31, 2023 were repayments on our Senior Secured Credit Facility, cash dividend payments to our common stockholders, common stock repurchases, and capital expenditures on our existing oil and natural gas properties. As of March 31, 2023, working capital was $10.7 million, an increase of $4.6 million from working capital of $6.1 million as of June 30, 2022.

The Senior Secured Credit Facility has a maximum capacity of $50.0 million subject to a borrowing base determined by the lender based on the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $50.0 million. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026.

Borrowings bear interest, at our option, at either the LIBOR plus 2.75% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. On May 5, 2023, our benchmark interest rate was converted to SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR. For the nine months ended March 31, 2023, the weighted average interest on our borrowings was 5.25%. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. It also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of March 31, 2023, we were in compliance with all covenants under the Senior Secured Credit Facility.

On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among other things, extends the maturity of our Senior Secured Credit Facility to April 9, 2026, converts our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modifies the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million.

On February 7, 2022, we entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as amended above, to the extent it exceeds the borrowing base then in effect. This amendment also required us to enter into hedges for the 12-month period ending February 2023, covering 25% of expected oil and natural gas production over that period.

On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby we must hedge a certain amount of our future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in the Ninth Amendment, as discussed above.

On August 5, 2021, we entered into the Seventh Amendment of our Senior Secured Credit Facility which, among other things, added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the consolidated tangible net worth covenant level was reduced to $40.0 million from $50.0 million.

We have historically funded operations through cash from operations and working capital. Our primary source of cash is the sale of produced crude oil, natural gas, and NGLs. A portion of these cash flows is used to fund capital expenditures and pay cash dividends to shareholders. We expect to fund near-future capital development activities for our properties with cash flows from operating activities and existing working capital.

We are pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, we have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility, totaling $50.0 million as of March 31, 2023. We also have an effective shelf registration statement with the SEC under which we may issue up to $500.0 million of new debt or equity securities.

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 38 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase dividends over time, as appropriate. In light of our improving financial performance and industry outlook, the Board of Directors has increased the dividend rate over the past two years, with the most recent increase occurring on September 12, 2022, when the Board of Directors declared a dividend of $0.12 per share that was paid on September 30, 2022. On May 8, 2023, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on June 15, 2023 and payable on June 30, 2023.

On September 8, 2022, our Board of Directors approved a share repurchase program, under which we are authorized to repurchase up to $25.0 million of our common stock through December 31, 2024. We intend to fund any repurchases from working capital and cash provided by operating activities. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return.

Once we completed the repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout period in December 2022, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan is effective until June 30, 2023, unless extended, renewed or terminated, and has a maximum authorized amount of $5.0 million over that period. We may alter the terms of the plan from time to time to the extent we determine changes are necessary to achieve the intended objectives of the repurchase program. During the three months ended March 31, 2023, 0.6 million shares of our common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.

### Capital Expenditures

During the nine months ended March 31, 2023, we incurred $4.4 million on development capital expenditures and $0.1 million for plugging and abandoning costs in the Jonah Field, Williston Basin, Barnett Shale and Hamilton Dome Field. During the current quarter, we participated in the completion and fracture stimulation of a vertical Bakken well and are waiting on results.

Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2023, we expect budgeted capital expenditures to be in the range of $6.0 million to $7.0 million, which excludes any potential acquisitions. These expenditures include anticipated capital costs at Delhi field for an NGL plant heat exchanger project, projected to improve operational efficiency throughout the year, which is currently underway and expected to be online before our fiscal year-end. As of March 31, 2023, we have incurred approximately $0.6 million related to this project. Our expected capital expenditures for fiscal year 2023 also include participating in another vertical recompletion in the Williston Basin. The timing of the two sidetrack locations targeting the Birdbear formation has been pushed to fiscal year 2024 due to delays in obtaining pooling and spacing orders with the state of North Dakota. We anticipate this permitting to be completed in the first fiscal quarter of 2024.

Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and current working capital, and as needed from borrowings under our Senior Secured Credit Facility.

### Full Cost Pool Ceiling Test

Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of March 31, 2023 were $91.38 per barrel of oil, $5.97 per MMBtu of natural gas and $47.07 per barrel of NGLs. As of March 31, 2023, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling. If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of March 31, 2023 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Using the April 2023 West Texas Intermediate (“WTI”) price of $75.68 per barrel of oil and the Henry Hub price of $2.10 per MMBtu of natural gas and holding these prices constant for two months to create a trailing 12-month period of average prices that is more reflective of recent price trends, our ceiling test calculation would not have generated an impairment, holding all other inputs and factors constant.

### Overview of Cash Flow Activities

| ​ ​ ​ | ​ ​ | ​ ​ Nine Months Ended March 31, 2023 | ​ | ​ ​ 2022 | ​ ​ | ​ ​ ​ ​ Change |
| --- | --- | ---: | --- | ---: | --- | ---: |
| Cash flows provided by operating activities | ​ | $51,719 | ​ | $28,691 | ​ | $23,028 |
| Cash flows used in investing activities | ​ | ​ (4,265) | ​ | ​ (28,140) | ​ | ​ 23,875 |
| Cash flows (used in) provided by financing activities | ​ | ​ (37,347) | ​ | ​ 7,541 | ​ | ​ (44,888) |
| Net increase in cash and cash equivalents | ​ | $10,107 | ​ | $8,092 | ​ | $2,015 |

Cash provided by operating activities for the nine months ended March 31, 2023 increased $23.0 million from the nine months ended March 31, 2022 primarily due to an increase in revenues. Total revenues increased $43.4 million as compared to the prior year period driven by an increase in our average realized price per barrel of oil equivalent (“BOE”) and an increase in our average daily production primarily due to our acquisition of non-operated working interests in the Williston Basin and Jonah Field in January 2022 and April 2022, respectively.

Cash used in investing activities for the nine months ended March 31, 2023 decreased $23.9 million from the nine months ended March 31, 2022 primarily due the $25.7 million acquisition of our Williston Basin properties in January 2022 and a $1.5 million deposit made in February 2022 for our acquisition in the Jonah Field partially offset by an increase in development capital expenditures in the current fiscal year.

Net cash flows used in financing activities for the nine months ended March 31, 2023 were $37.3 million which included the repayment of $21.3 million of borrowings outstanding under our Senior Secured Credit Facility, $12.1 million in dividends paid to our common stockholders, and $3.9 million paid to repurchase shares of common stock under our share repurchase program. Net cash flows provided by financing activities for the nine months ended March 31, 2022 were $7.5 million which primarily included $16.0 million in net borrowings under our Senior Secured Credit Facility offset by $8.4 million in dividends paid to our common stockholders.

### Results of Operations

### Three Months Ended March 31, 2023 and 2022

We reported net income of $14.0 million and $5.7 million for the three months ended March 31, 2023 and 2022, respectively. The following table summarizes the comparison of financial information for the periods presented:

*(in thousands, except per unit and per BOE amounts)*

| ​ ​ | ​ ​ ​ | ​ ​ Three Months Ended March 31, 2023 | ​ ​ | ​ ​ 2022 | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance % |
| --- | --- | --- | --- | --- | --- | --- | --- | ---: |
| Net income (loss) | ​ | $13,957 | ​ | $5,705 | ​ | $8,252 | ​ | 144.6% |
| Revenues: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Crude oil | ​ | ​ 11,799 | ​ | ​ 14,868 | ​ | ​ (3,069) | ​ | (20.6)% |
| Natural gas | ​ | ​ 21,598 | ​ | ​ 6,070 | ​ | ​ 15,528 | ​ | 255.8% |
| Natural gas liquids | ​ | ​ 3,470 | ​ | ​ 4,750 | ​ | ​ (1,280) | ​ | (26.9)% |
| Total revenues | ​ | ​ 36,867 | ​ | ​ 25,688 | ​ | ​ 11,179 | ​ | 43.5% |
| Operating costs: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Lease operating costs: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| CO2 costs | ​ | ​ 1,821 | ​ | ​ 2,321 | ​ | ​ (500) | ​ | (21.5)% |
| Ad valorem and production taxes | ​ | ​ 1,642 | ​ | ​ 1,449 | ​ | ​ 193 | ​ | 13.3% |
| Other lease operating costs | ​ | ​ 10,107 | ​ | ​ 8,314 | ​ | ​ 1,793 | ​ | 21.6% |
| Depletion, depreciation, and accretion: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Depletion of full cost proved oil and natural gas properties | ​ | ​ 3,098 | ​ | ​ 1,602 | ​ | ​ 1,496 | ​ | 93.4% |
| Accretion of asset retirement obligations | ​ | ​ 285 | ​ | ​ 135 | ​ | ​ 150 | ​ | 111.1% |
| General and administrative expenses: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| General and administrative | ​ | ​ 1,814 | ​ | ​ 1,175 | ​ | ​ 639 | ​ | 54.4% |
| Stock-based compensation | ​ | ​ 453 | ​ | ​ 340 | ​ | ​ 113 | ​ | 33.2% |
| Other income (expense): | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Net gain (loss) on derivative contracts | ​ | ​ 270 | ​ | ​ (2,591) | ​ | ​ 2,861 | ​ | (110.4)% |
| Interest and other income | ​ | ​ 13 | ​ | ​ 2 | ​ | ​ 11 | ​ | 550.0% |
| Interest expense | ​ | ​ (32) | ​ | ​ (170) | ​ | ​ 138 | ​ | (81.2)% |
| Income tax (expense) benefit | ​ | ​ (3,941) | ​ | ​ (1,888) | ​ | ​ (2,053) | ​ | 108.7% |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| **Production:** | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Crude oil (MBBL) | ​ | ​ 167 | ​ | ​ 163 | ​ | ​ 4 | ​ | 2.5% |
| Natural gas (MMCF) | ​ | ​ 2,204 | ​ | ​ 1,429 | ​ | ​ 775 | ​ | 54.2% |
| Natural gas liquids (MBBL) | ​ | ​ 104 | ​ | ​ 100 | ​ | ​ 4 | ​ | 4.0% |
| Equivalent (MBOE)(1) | ​ | ​ 638 | ​ | ​ 501 | ​ | ​ 137 | ​ | 27.3% |
| Average daily production (BOEPD)(1) | ​ | ​ 7,089 | ​ | ​ 5,567 | ​ | ​ 1,522 | ​ | 27.3% |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Average price per unit(2): | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Crude oil (BBL) | ​ | $70.65 | ​ | $91.21 | ​ | $(20.56) | ​ | (22.5)% |
| Natural gas (MCF) | ​ | ​ 9.80 | ​ | ​ 4.25 | ​ | ​ 5.55 | ​ | 130.6% |
| Natural Gas Liquids (BBL) | ​ | ​ 33.37 | ​ | ​ 47.50 | ​ | ​ (14.13) | ​ | (29.7)% |
| Equivalent (BOE)(1) | ​ | ​ 57.79 | ​ | ​ 51.27 | ​ | ​ 6.52 | ​ | 12.7% |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| **Average cost per unit:** | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Operating costs: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Lease operating costs: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| CO2 costs | ​ | $2.85 | ​ | $4.63 | ​ | ​ (1.78) | ​ | (38.4)% |
| Ad valorem and production taxes | ​ | ​ 2.57 | ​ | ​ 2.89 | ​ | ​ (0.32) | ​ | (11.1)% |
| Other lease operating costs | ​ | ​ 15.84 | ​ | ​ 16.59 | ​ | ​ (0.75) | ​ | (4.5)% |
| Depletion of full cost proved oil and natural gas properties | ​ | ​ 4.86 | ​ | ​ 3.20 | ​ | ​ 1.66 | ​ | 51.9% |
| General and administrative expenses: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| General and administrative | ​ | ​ 2.84 | ​ | ​ 2.35 | ​ | ​ 0.49 | ​ | 20.9% |
| Stock-based compensation | ​ | ​ 0.71 | ​ | ​ 0.68 | ​ | ​ 0.03 | ​ | 4.4% |

***(1)*** Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

***(2)*** Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting.

#### Revenues

Crude oil, natural gas and NGL revenues were $36.9 million and $25.7 million for the three months ended March 31, 2023 and 2022, respectively. The increase in revenue is primarily due to an increase in production coupled with an increase in our average realized price per BOE. Average daily equivalent production increased 27.3% from 5,567 BOEPD to 7,089 BOEPD due to the acquisitions of non-operated working interests in the Jonah Field and Williston Basin in the second half of fiscal year 2022, which collectively increased current quarter production by approximately 1,913 BOEPD. In total, our average realized commodity price (excluding the impact of derivative contracts) increased approximately $6.52 per BOE, or 12.7%, over the year-ago quarter, primarily due to 130.6% increase in our realized natural gas prices from the year-ago quarter. This was attributed to the benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $20.31 per MCF for the current quarter. This increase was offset by decreases in realized crude oil and NGL prices of 22.5% and 29.7%, respectively, from the year-ago quarter, primarily as a result of the decline in WTI pricing.

#### Lease Operating Costs

Ad valorem and production taxes were $1.6 million and $1.4 million for the three months ended March 31, 2023 and 2022, respectively. The increase in taxes is primarily due to increased production volumes and the increase in natural gas pricing described above as production taxes are based on sales at the wellhead. On a per unit basis, ad valorem and production taxes were $2.57 per BOE and $2.89 per BOE for the three months ended March 31, 2023 and 2022, respectively. The decrease on a per BOE basis is due to an increase in production volumes related to our acquisition of interests in the Williston Basin where we do not incur Ad valorem taxes.

The following table summarizes CO2 costs per MCF and CO2 volumes for the three months ended March 31, 2023 and 2022. CO2 purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO2 is priced at 1% of the realized oil price in the field per MCF, plus sales taxes and transportation costs as per contract terms.

| ​ ​ ​ | ​ ​ ​ | ​ ​ Three Months Ended March 31, 2023 | ​ | ​ ​ 2022 | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance % |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| CO2 costs per MCF | ​ | $0.92 | ​ | $1.12 | ​ | $(0.20) | ​ | (17.9)% |
| CO2 volumes (MMCF per day, gross) | ​ | ​ 91.7 | ​ | ​ 96.0 | ​ | ​ (4.3) | ​ | (4.5)% |

The $0.5 million decrease in CO2 costs for the current quarter was primarily due to a 17.9% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price in addition to a 4.5% decrease in purchased CO2 volumes. In the current quarter, the decrease in volumes is due to Denbury’s reduced allocation of CO2 to the Delhi Field. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO2 pipeline which is owned and operated by Denbury. On a per unit basis, CO2 costs were $2.85 per BOE and $4.63 per BOE for the three months ended March 31, 2023 and 2022, respectively. This decrease was due to the aforementioned decrease in the average realized oil price in the field as well as an increase in our total production since the year-ago quarter due to our acquisitions in the Jonah Field and Williston Basin in the second half of fiscal year 2022.

Other lease operating costs included remedial workover costs and gathering and transportation costs for our oil and natural gas production. Compared to the year-ago quarter, other lease operating costs increased approximately $1.8 million, or 21.6% in the current quarter primarily due to our acquisitions in the Jonah Field and Williston Basin in April 2022 and January 2022, respectively. Other lease operating costs on a per BOE basis decreased to $15.84 per BOE from $16.59 per BOE in the year-ago quarter.

#### Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $1.5 million or 93.4% from the year-ago quarter of $1.6 million to $3.1 million for the current quarter primarily due to an increase in production. On a per unit basis, depletion expense was $4.86 per BOE and $3.20 per BOE for the three months ended March 31, 2023 and 2022, respectively. The depletable base of our unit of production calculation increased due to our acquisitions in fiscal year 2022 and increases in our future development costs associated with our proved undeveloped reserve additions at fiscal year-end 2022. These increases were partially offset by an increase in proved reserve volumes.

#### General and Administrative Expenses

General and administrative expenses for the current quarter increased $0.6 million, or 54.4%, to $1.8 million compared to $1.2 million for the year-ago quarter. The increase is primarily due to approximately $0.3 million for salary and employee benefits due to additional personnel and $0.2 million for professional fees related to accounting and audit-related services.

#### Stock-based Compensation Expense

Stock-based compensation expense for the current quarter increased $0.1 million, or 33.2%, to $0.5 million compared to $0.3 million for the year-ago quarter. The increase is primarily due to the addition of new personnel, including our new COO, and the associated new awards granted during the current year period.

#### Net Gain (Loss) on Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As a result of our acquisitions during fiscal year 2022 and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms set in the Senior Secured Credit Facility to hedge a portion of our production. The increase in commodity prices since entering into the hedges and the subsequent decline in commodity prices resulted in a realized loss on derivative contracts for the year-ago quarter and a realized gain on derivative assets for the current quarter. As of March 31, 2023, we did not have any open crude oil or natural gas derivative contracts.

*(in thousands, except per unit and per BOE amounts)*

| ​ ​ ​ | ​ ​ ​ | ​ ​ Three Months Ended March 31, 2023 | ​ | ​ ​ 2022 | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance % |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Realized gain (loss) on derivative contracts | ​ | $465 | ​ | $(193) | ​ | $658 | ​ | (340.9)% |
| Unrealized gain (loss) on derivative contracts | ​ | ​ (195) | ​ | ​ (2,398) | ​ | ​ 2,203 | ​ | (91.9)% |
| Total net gain (loss) on derivative contracts | ​ | $270 | ​ | $(2,591) | ​ | $2,861 | ​ | (110.4)% |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Average realized crude oil price per BBL | ​ | $70.65 | ​ | $91.21 | ​ | $(20.56) | ​ | (22.5)% |
| Cash effect of oil derivative contracts per BBL | ​ | ​ — | ​ | ​ (1.18) | ​ | ​ 1.18 | ​ | (100.0)% |
| Crude oil price per Bbl (including impact of realized derivatives) | ​ | $70.65 | ​ | $90.03 | ​ | $(19.38) | ​ | (21.5)% |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Average realized natural gas price per MCF | ​ | $9.80 | ​ | $4.25 | ​ | $5.55 | ​ | 130.6% |
| Cash effect of natural gas derivative contracts per MCF | ​ | ​ 0.21 | ​ | ​ — | ​ | ​ 0.21 | ​ | —% |
| Natural gas price per Mcf (including impact of realized derivatives) | ​ | $10.01 | ​ | $4.25 | ​ | $5.76 | ​ | 135.5% |

#### Interest Expense

Interest expense decreased $0.1 million compared to the year-ago quarter primarily due to no borrowings outstanding on our Senior Secured Credit Facility during the current quarter.

#### Income Tax (Expense) Benefit

For the three months ended March 31, 2023, we recognized income tax expense of $3.9 million on net income before income taxes of $17.9 million compared to income tax expense of $1.9 million on net income before income taxes of $7.6 million for the three months ended March 31, 2022. Our effective tax rates for current quarter is 22.0% compared to 24.9% in the year-ago quarter.

### Nine Months Ended March 31, 2023 and 2022

We reported net income of $35.1 million and $17.8 million for the nine months ended March 31, 2023 and 2022, respectively. The following table summarizes the comparison of financial information for the periods presented:

*(in thousands, except per unit and per BOE amounts)*

| ​ ​ | ​ ​ ​ | ​ ​ Nine Months Ended March 31, 2023 | ​ | ​ ​ 2022 | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance % |
| --- | --- | --- | --- | --- | --- | --- | --- | ---: |
| Net income (loss) | ​ | $35,051 | ​ | $17,756 | ​ | $17,295 | ​ | 97.4% |
| Revenues: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Crude oil | ​ | ​ 40,062 | ​ | ​ 34,309 | ​ | ​ 5,753 | ​ | 16.8% |
| Natural gas | ​ | ​ 58,816 | ​ | ​ 20,698 | ​ | ​ 38,118 | ​ | 184.2% |
| Natural gas liquids | ​ | ​ 11,462 | ​ | ​ 11,899 | ​ | ​ (437) | ​ | (3.7)% |
| Total revenues | ​ | ​ 110,340 | ​ | ​ 66,906 | ​ | ​ 43,434 | ​ | 64.9% |
| Operating costs: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Lease operating costs: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| CO2 costs | ​ | ​ 6,027 | ​ | ​ 5,135 | ​ | ​ 892 | ​ | 17.4% |
| Ad valorem and production taxes | ​ | ​ 7,001 | ​ | ​ 3,968 | ​ | ​ 3,033 | ​ | 76.4% |
| Other lease operating costs | ​ | ​ 34,699 | ​ | ​ 22,277 | ​ | ​ 12,422 | ​ | 55.8% |
| Depletion, depreciation, and accretion: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Depletion of full cost proved oil and natural gas properties | ​ | ​ 9,598 | ​ | ​ 4,146 | ​ | ​ 5,452 | ​ | 131.5% |
| Depreciation of other property and equipment | ​ | ​ — | ​ | ​ 4 | ​ | ​ (4) | ​ | (100.0)% |
| Accretion of asset retirement obligations | ​ | ​ 841 | ​ | ​ 339 | ​ | ​ 502 | ​ | 148.1% |
| General and administrative expenses: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| General and administrative | ​ | ​ 6,165 | ​ | ​ 4,410 | ​ | ​ 1,755 | ​ | 39.8% |
| Stock-based compensation | ​ | ​ 1,155 | ​ | ​ 868 | ​ | ​ 287 | ​ | 33.1% |
| Other income (expense): | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Net gain (loss) on derivative contracts | ​ | ​ 513 | ​ | ​ (2,591) | ​ | ​ 3,104 | ​ | (119.8)% |
| Interest and other income | ​ | ​ 26 | ​ | ​ 12 | ​ | ​ 14 | ​ | 116.7% |
| Interest expense | ​ | ​ (404) | ​ | ​ (272) | ​ | ​ (132) | ​ | 48.5% |
| Income tax (expense) benefit | ​ | ​ (9,938) | ​ | ​ (5,152) | ​ | ​ (4,786) | ​ | 92.9% |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| **Production:** | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Crude oil (MBBL) | ​ | ​ 501 | ​ | ​ 447 | ​ | ​ 54 | ​ | 12.1% |
| Natural gas (MMCF) | ​ | ​ 7,065 | ​ | ​ 4,728 | ​ | ​ 2,337 | ​ | 49.4% |
| Natural gas liquids (MBBL) | ​ | ​ 325 | ​ | ​ 260 | ​ | ​ 65 | ​ | 25.0% |
| Equivalent (MBOE)(1) | ​ | ​ 2,004 | ​ | ​ 1,495 | ​ | ​ 509 | ​ | 34.0% |
| Average daily production (BOEPD)(1) | ​ | ​ 7,314 | ​ | ​ 5,456 | ​ | ​ 1,858 | ​ | 34.1% |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Average price per unit(2): | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Crude oil (BBL) | ​ | $79.96 | ​ | $76.75 | ​ | $3.21 | ​ | 4.2% |
| Natural gas (MCF) | ​ | ​ 8.32 | ​ | ​ 4.38 | ​ | ​ 3.94 | ​ | 90.0% |
| Natural Gas Liquids (BBL) | ​ | ​ 35.27 | ​ | ​ 45.77 | ​ | ​ (10.50) | ​ | (22.9)% |
| Equivalent (BOE)(1) | ​ | ​ 55.06 | ​ | ​ 44.75 | ​ | ​ 10.31 | ​ | 23.0% |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| **Average cost per unit:** | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Operating costs: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Lease operating costs: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| CO2 costs | ​ | $3.01 | ​ | $3.43 | ​ | ​ (0.42) | ​ | (12.2)% |
| Ad valorem and production taxes | ​ | ​ 3.49 | ​ | ​ 2.65 | ​ | ​ 0.84 | ​ | 31.7% |
| Other lease operating costs | ​ | ​ 17.31 | ​ | ​ 14.90 | ​ | ​ 2.41 | ​ | 16.2% |
| Depletion of full cost proved oil and natural gas properties | ​ | ​ 4.79 | ​ | ​ 2.77 | ​ | ​ 2.02 | ​ | 72.9% |
| General and administrative expenses: | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| General and administrative | ​ | ​ 3.08 | ​ | ​ 2.95 | ​ | ​ 0.13 | ​ | 4.4% |
| Stock-based compensation | ​ | ​ 0.58 | ​ | ​ 0.58 | ​ | ​ — | ​ | —% |

***(1)*** Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

***(2)*** Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting.

#### Revenues

Crude oil, natural gas and NGL revenues were $110.3 million and $66.9 million for the nine months ended March 31, 2023 and 2022, respectively. The increase in revenue is primarily due to our acquisitions of non-operated working interests in the Jonah Field and Williston Basin in the second half of fiscal year 2022. Average daily equivalent production increased 34.1% from 5,456 BOEPD in the prior year period to 7,314 BOEPD in the current period. Production increases were driven by our acquisitions of non-operated working interests in the Jonah Field and Williston Basin in the second half of fiscal year 2022, which increased the current nine months ended production by approximately 2,253 BOEPD. Our average realized commodity price (excluding the impact of derivative contracts) for the nine months ended March 31, 2023 increased approximately $10.31 per BOE, or 23.0%, over the prior year period. Realized oil and natural gas prices increased approximately 4.2% and 90.0%, respectively, over the prior year period. The increase in realized natural gas prices is primarily attributed to the benefit of strong natural gas price differentials received at the Jonah Field where our realized price for natural gas for the current year period was $12.99 per MCF. This increase is offset by a 23% decrease in realized NGL prices from the prior year period.

#### Lease Operating Costs

Ad valorem and production taxes were $7.0 million and $4.0 million for the nine months ended March 31, 2023 and 2022, respectively. On a per unit basis, ad valorem and production taxes were $3.49 per BOE and $2.65 per BOE for the nine months ended March 31, 2023 and 2022, respectively. The increase in ad valorem and production taxes is primarily due to increases in oil and natural gas prices and increased production volumes described above as production taxes are based on sales at the wellhead.

The following table summarizes CO2 costs per Mcf and CO2 volumes for the nine months ended March 31, 2023 and 2022. CO2 purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO2 is priced at 1% of the realized oil price in the field per MCF, plus sales taxes and transportation costs as per contract terms.

| ​ ​ ​ | ​ ​ ​ | ​ ​ Nine Months Ended March 31, 2023 | ​ | ​ ​ 2022 | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance % |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| CO2 costs per MCF | ​ | $1.01 | ​ | $0.99 | ​ | $0.02 | ​ | 2.0% |
| CO2 volumes (MMCF per day, gross) | ​ | ​ 90.8 | ​ | ​ 79.6 | ​ | ​ 11.2 | ​ | 14.1% |

The $0.9 million increase in CO2 costs for the nine months ended March 31, 2023 was primarily due to a 14.1% increase in purchased CO2 volumes combined with a 2.0% increase in CO2 costs per MCF, which was driven by an increase in our average realized oil price. CO2 purchases were temporarily suspended throughout the prior year period due to preventative maintenance on the pipeline that supplies newly purchased CO2 to the Delhi Field. Additionally, CO2 purchase nominations increased from the prior year period to compensate for reduced reservoir pressure. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO2 pipeline which is owned and operated by Denbury. On a per unit basis, CO2 costs were $3.01 per BOE and $3.43 per BOE for the nine months ended March 31, 2023 and 2022, respectively. The decrease on a per BOE basis is due to the increase in total production since the prior year period, from our acquisitions in the Jonah Field and Williston Basin in the second half of fiscal year 2022.

Other lease operating costs include remedial workover costs and gathering and transportation costs for our oil and natural gas production. Compared to the prior year period, other lease operating costs increased 55.8% in the nine months ended March 31, 2023 primarily due to the acquisitions in the Jonah Field and Williston Basin in April 2022 and January 2022, respectively. Discussed further below, other lease operating costs on a per BOE basis increased to $17.31 per BOE from $14.90 per BOE in the year-ago quarter. Other lease operating costs per BOE for our Jonah Field were approximately $10.69 per BOE for the nine months ended March 31, 2023. Other lease operating costs per BOE for the Williston Basin were approximately $26.34 per BOE for the nine months ended March 31, 2023, an increase of approximately $6.11 per BOE from the prior year period, primarily as a result of increased remedial workovers. Other lease operating costs per BOE for the Barnett Shale were approximately $17.77 for the nine months ended March 31, 2023, an increase of approximately $4.50 per BOE from the prior year period, due to higher gathering, transportation and other expenses as a result of higher commodity prices through the first half of fiscal year 2023.

#### Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $5.5 million or 131.5% from $4.1 million to $9.6 million for the nine months ended March 31, 2023 primarily due to an increase in production. On a per unit basis, depletion expense was $4.79 per BOE and $2.77 per BOE for the nine months ended March 31, 2023 and 2022, respectively. The depletable base of our unit of production calculation increased due to our acquisitions in fiscal year 2022 and increases in our future development costs associated with our proved undeveloped reserve additions at fiscal year-end 2022. These increases were partially offset by an increase in proved reserve volumes.

#### General and Administrative Expenses

General and administrative expenses for the nine months ended March 31, 2023 increased $1.8 million, or 39.8%, to $6.2 million compared to $4.4 million for the prior year period. The increase is primarily due to approximately $0.7 million for salary and employee benefits due to additional personnel added since the prior year period and $0.3 million in professional fees associated with our search for a CEO. The remaining increase is associated with fees for accounting and audit-related services and public reporting expenses.

#### Stock-based Compensation Expense

Stock-based compensation expense for the nine months ended March 31, 2023 increased $0.3 million, or 33.1%, to $1.2 million compared to $0.9 million for the prior year period. The increase is primarily due to the addition of new personnel, including our new COO, and the associated new awards granted during the current year period. Approximately $0.1 million of the current year period increase related to a one-time share award granted in November 2022, which vested and was fully expensed immediately.

#### Net Gain (Loss) on Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As a result of our acquisitions during fiscal year 2022 and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms set in the Senior Secured Credit Facility to hedge a portion of our production. The increase in commodity prices since entering into the hedges resulted in realized losses on derivative contracts for the current year and prior year periods. As of March 31, 2023, we did not have any open crude oil or natural gas derivative contracts.

*(in thousands, except per unit and per BOE amounts)*

| ​ ​ ​ | ​ ​ ​ | ​ ​ Nine Months Ended March 31, 2023 | ​ | ​ ​ 2022 | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance | ​ ​ ​ | ​ ​ ​ ​ ​ ​ Variance % |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Realized gain (loss) on derivative contracts | ​ | $(1,481) | ​ | $(193) | ​ | $(1,288) | ​ | 667.4% |
| Unrealized gain (loss) on derivative contracts | ​ | ​ 1,994 | ​ | ​ (2,398) | ​ | ​ 4,392 | ​ | (183.2)% |
| Total net gain (loss) on derivative contracts | ​ | $513 | ​ | $(2,591) | ​ | $3,104 | ​ | (119.8)% |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Average realized crude oil price per BBL | ​ | $79.96 | ​ | $76.75 | ​ | $3.21 | ​ | 4.2% |
| Cash effect of oil derivative contracts per BBL | ​ | ​ (0.49) | ​ | ​ (0.43) | ​ | ​ (0.06) | ​ | 14.0% |
| Crude oil price per Bbl (including impact of realized derivatives) | ​ | $79.47 | ​ | $76.32 | ​ | $3.15 | ​ | 4.1% |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Average realized natural gas price per MCF | ​ | $8.32 | ​ | $4.38 | ​ | $3.94 | ​ | 90.0% |
| Cash effect of natural gas derivative contracts per MCF | ​ | ​ (0.17) | ​ | ​ — | ​ | ​ (0.17) | ​ | —% |
| Natural gas price per Mcf (including impact of realized derivatives) | ​ | $8.15 | ​ | $4.38 | ​ | $3.77 | ​ | 86.1% |

36

#### Interest Expense

Interest expense increased $0.1 million for the nine months ended March 31, 2023 compared to the prior year period primarily due to increased borrowings outstanding on our Senior Secured Credit Facility used to acquire interests in the Williston Basin and Jonah Field during the second half of fiscal year 2022.

#### Income Tax (Expense) Benefit

For the nine months ended March 31, 2023, we recognized income tax expense of $9.9 million on net income before income taxes of $45.0 million compared to income tax expense of $5.2 million on net income before income taxes of $22.9 million for the nine months ended March 31, 2022. The effective tax rates were 22.1% and 22.5% for nine months ended March 31, 2023 and 2022, respectively.

### Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements. The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our unaudited condensed consolidated financial statements. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended June 30, 2022.

## Market risk

As filed, 2,229 characters.

#### Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil, natural gas, and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we monitor commodity prices to identify the potential need for the use of derivative financial instruments to provide partial protection against declines in oil and natural gas prices. We do not enter into derivative contracts for speculative trading purposes.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. For the derivative contracts settled during fiscal 2023 and 2022, we did not post collateral. We account for our derivative activities under the provisions of ASC 815, *Derivatives and Hedging, (“*ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “*Derivatives”* to our unaudited condensed consolidated financial statements for more details.

#### Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%. SOFR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. Under our current practices, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

## Controls and procedures

As filed, 1,997 characters.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s (“SEC”) rules and forms and that such information is accumulated and communicated to our management, including our Principal Executive Officer and Principal Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

As required by SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15(d)-15(e)) as of the end of the quarter covered by this report. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. Based on the foregoing, our Principal Executive Officer and Principal Financial Officer concluded that as of March 31, 2023 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms.

Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, during the quarter ended March 31, 2023, we have determined that there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Filed May 10, 2023.
Source: SEC EDGAR, the filing index for accession 0001558370-23-009105. Last ingested by Listed: Nov 3, 2026, 19:31 ET. No prices; not investment advice.