EVOLUTION PETROLEUM CORP
For the period ended Mar 31, 2024. Filed May 8, 2024.
View on SEC.govAbout this filing
A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2024 · Filed May 8, 2024
EPM$3.48+0.6%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2023-12-31; filed 2024-02-07.
0001558370-24-000857
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsExecutive OverviewLiquidity and Capital ResourcesCurrent report: 10-Q
Period ended 2024-03-31; filed 2024-05-08.
0001558370-24-007347
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsExecutive OverviewLiquidity and Capital ResourcesThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 58 previous paragraphs and 67 current paragraphs.
31 unchanged; 24 reworded; 9 added; 2 removed; 1 previous and 3 current paragraphs rearranged.
Tables are not compared: 1 previous and 1 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (9)
Current report
Our non-operated interests in the SCOOP and STACK plays, an oil and natural gas producing property in the Anadarko basin, consist of approximately 3% average net working interest and approximately 2% average net revenue interests located on approximately 3,700 net acres across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma. The oil and natural gas properties are primarily operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators.
Current report
On February 12, 2024, we closed the acquisitions of certain non-operated oil and natural gas assets in the SCOOP and STACK plays in central Oklahoma (the "SCOOP/STACK Acquisitions") from Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. After taking into account preliminary customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $40.5 million, which includes $43.8 million paid at closing less interim purchase price adjustments totaling approximately $3.3 million related to net cash flows earned on the properties from the effective date to the closing date. We expect to receive the remaining net cash flows from the properties between the effective date of November 1, 2023 and the closing date, at the final post-closing settlement process expected to occur during the fourth quarter of fiscal 2024.
Current report
On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility. This amendment required that we enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period. We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.
Current report
On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility. This amendment required that we enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period. We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.
Current report
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 defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required us to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected crude oil and natural gas production over that period.
Current report
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 minimum of 25% to 75% of 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 subsequent amendments, as discussed above.
Current report
In December 2022, we entered into a Rule 10b5-1 plan that authorized 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 was effective until June 30, 2023 and had a maximum authorized amount of $5.0 million over that period. During the three and nine 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 shares were subsequently cancelled.
Current report
repurchase program. During the three and nine months ended March 31, 2024, 0.1 million shares of the Company’s common stock have been repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs. These shares were subsequently cancelled.
Removed paragraphs (2)
Previous report
On January 5, 2024, we entered into separate Purchase and Sale Agreements (“PSAs”) with Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. Pursuant to the PSAs, we will acquire non-operating working interests in oil and natural gas properties in the SCOOP and STACK plays in central Oklahoma for a combined purchase price of approximately $43.5 million in cash (“the SCOOP/STACK Acquisitions”). Contemporaneous with the execution of the PSAs, we paid deposits totaling $3.26 million. We expect to fund the balance of the consideration to be paid in the transactions with a combination of cash on hand and borrowings under our senior secured credit facility.
Previous report
The effective date of these acquisitions is November 1, 2023 and each transaction is expected to close in mid-February during the third quarter of fiscal 2024. The PSAs governing each transaction contain customary representations and warranties, covenants, indemnification, closing conditions and termination provisions and also provide for various purchase price adjustments, including adjusting the purchase price for the net cash flows of the properties between the effective date and closing date of the acquisition, to be calculated as of the closing date.
Reworded paragraphs (24)
Previous wording
“Current quarter” refers to the three months ended December 31, 2023, our first quarter of fiscal year 2024.
Current wording
“Current quarter” refers to the three months ended March 31, 2024, our third quarter of fiscal year 2024.
Previous wording
“Year-ago quarter” refers to the three months ended December 31, 2022, our first quarter of fiscal year 2023.
Current wording
“Year-ago quarter” refers to the three months ended March 31, 2023, our third quarter of fiscal year 2023.
Previous wording
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; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; as well as small overriding royalty interests in four onshore central Texas wells.
Current wording
Our oil and natural gas properties consist of non-operated interests in the following areas: the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; 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.
Previous wording
Our non-operated interests in the Chaveroo oilfield consist of a 50% net working interest, with an associated 41% revenue interest, in approximately 1,625 gross undeveloped acres associated with nine initial development locations with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price. The field is operated by PEDEVCO Corp. (“PEDEVCO”). See*“Chaveroo Oilfield Participation Agreement”* below for further information.
Current wording
Our non-operated interests in the Chaveroo oilfield consist of a 50% net working interest, with an associated 41% revenue interest, in approximately 1,625 gross acres associated with ten development locations with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price. The field is operated by PEDEVCO Corp. (“PEDEVCO”). See*“Chaveroo Oilfield Participation Agreement”* below for further information.
Previous wording
Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 43,300 net acres (approximately 92% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management, an established operator in the geographic region.
Current wording
Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 43,300 net acres (approximately 92% held by production) across Billings, Golden Valley, and McKenzie Counties in North
Previous wording
Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of 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, who owns the majority of the
Current wording
Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of 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, who owns the 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.
Previous wording
Our non-operated interests in the Delhi Field, a CO 2-EOR project producing oil and NGLs, 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.
Current wording
Our non-operated interests in the Delhi Field, a CO 2-EOR project producing oil and NGLs, 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”), which was acquired by Exxon Mobil Corporation during the current fiscal year. 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.
Previous wording
The acquired assets consist of an average working interest of approximately 3% net to us, in 231 producing wells and as of the effective date, 21 gross drilled and uncompleted wells to be funded through completion by the sellers, in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, and Stephens counties, Oklahoma. The acquisitions also include approximately 3,700 net acres with more than 300 associated potential drilling opportunities.
Current wording
The acquired assets consist of an average net working interest of approximately 3% in 247 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties, Oklahoma. The acquisitions also include approximately 3,700 net acres with more than 275 associated potential drilling opportunities.
Previous wording
In November 2023, 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 is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 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 our repurchase program. No shares were repurchased under this program during the period ended December 31, 2023.
Current wording
In November 2023, 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 is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 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 our repurchase program. During the three and nine months ended March 31, 2024, 0.1 million shares of the Company’s common stock have been repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs. These shares were subsequently cancelled.
Previous wording
During the three months ended September 30, 2023, we paid total cash consideration of $0.4 million, which includes less than $0.1 million of capitalized transaction costs, in exchange for a 50% working interest share in 1,625 gross undeveloped leasehold acres associated with two initial development blocks, comprised of nine development well locations. Following the completion of the initial nine development wells, we will have the right, but not the obligation, to elect to participate in the next development block. The Participation Agreement initially includes up to 80 gross drilling locations across twelve development blocks. Refer to Capital Expenditures below for a further discussion of Chaveroo drilling and completion activities since entering into the Participation Agreement.
Current wording
During the three months ended September 30, 2023, we paid total cash consideration of $0.4 million, which includes less than $0.1 million of capitalized transaction costs, in exchange for a 50% working interest share in 1,625 gross leasehold acres associated with two initial development blocks. As of March 31, 2024, we have participated in the drilling and completion of the first development block which consisted of three gross (1.5 net ) wells. Following the completion of the second development block, we will have the right, but not the obligation, to elect to participate in additional development blocks. The Participation Agreement initially includes up to 80 gross drilling locations across twelve development blocks. Refer to Capital Expenditures below for a further discussion of Chaveroo drilling and completion activities since entering into the Participation Agreement.
Previous wording
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.
Current wording
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 recovered primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses. During the current year, natural gas prices have declined primarily due to a warmer winter, and during the current quarter, oil prices have increased somewhat due to geopolitical factors and increased demand relative to supply.
Previous wording
As of December 31, 2023 and June 30, 2023, we had no borrowings outstanding on our Senior Secured Credit Facility. As of December 31, 2023, we had $8.5 million in cash and cash equivalents compared to $11.0 million in cash and cash equivalents at June 30, 2023. Our primary sources of liquidity and capital resources during the six months ended December 31, 2023 were cash provided by operations and the unused portion of our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the three months ended December 31, 2023 were cash dividend payments to our common stockholders, capital expenditures on our existing oil and natural gas properties, and initial cash consideration paid for unevaluated oil and natural gas properties under our Participation Agreement with PEDEVCO. As of December 31, 2023, working capital was $6.6 million, a decrease of $2.3 million from working capital of $8.9 million as of June 30, 2023.
Current wording
As of March 31, 2024, we had $3.1 million in cash and cash equivalents and $42.5 million outstanding on our Senior Secured Credit Facility compared to $11.0 million in cash and cash equivalents and no borrowings outstanding on our Senior Secured Credit Facility at June 30, 2023. Our primary sources of liquidity and capital resources during the nine months ended March 31, 2024 were cash provided by operations as well as net borrowings under our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the nine months ended March 31, 2024 were our SCOOP/STACK Acquisitions, cash dividend payments to our common stockholders, and development capital expenditures, primarily at Chaveroo oilfield where we participated in drilling three gross (1.5 net) wells. As of March 31, 2024, working capital was $7.6 million, a decrease of $1.3 million from working capital of $8.9 million as of June 30, 2023.
Previous wording
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.
Current wording
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, with $42.5 million drawn as of March 31, 2024. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026.
Previous wording
Borrowings bear interest, at our option, at either the SOFR plus 2.80% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. During the six months ended December 31, 2023, we did not have any borrowings outstanding under our Senior Secured Credit Facility. 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 December 31, 2023, we were in compliance with all covenants under the Senior Secured Credit Facility.
Current wording
Borrowings bear interest, at our option, at either the SOFR plus 2.80% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. For the nine months ended March 31, 2024 and 2023, the weighted average interest on our borrowings was 8.13% and 5.25%, respectively. 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, 2024, we were in compliance with all covenants under the Senior Secured Credit Facility.
Previous wording
On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among other things, extended the maturity of our Senior Secured Credit Facility to April 9, 2026, converted our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modified the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value. The required amount of hedged oil and natural gas production is related to the amount of borrowings outstanding. At each redetermination, our Margined Collateral Value takes into account the estimated value of our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. We expect to be subject to these hedge requirements upon the closing of our pending SCOOP/STACK Acquisitions.
Current wording
Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value. The required amount of hedged oil and natural gas production is related to the amount of borrowings outstanding. At each redetermination, our Margined Collateral Value takes into account the estimated value of our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.
Previous wording
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 December 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.
Current wording
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 $7.5 million as of March 31, 2024. 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.
Previous wording
Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 41 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. On February 5, 2024, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on March 15, 2024 and payable on March 28, 2024.
Current wording
Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 42 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. On May 6, 2024, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on June 14, 2024 and payable on June 28, 2024.
Previous wording
In November 2023, 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 is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 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 our repurchase program.
Current wording
In November 2023, 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 is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 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 our
Previous wording
During the six months ended December 31,2023, we incurred $5.7 million in capital expenditures. During the current quarter, we participated in the drilling and completion of the initial three wells in the Chaveroo Field. During the first fiscal quarter, we participated in the drilling and completion of two new wells in the Delhi Field. First production at Chaveroo Field is expected in February 2024. Production of the Delhi wells came online in the first fiscal quarter of 2024 and produced consistently in the second fiscal quarter.
Current wording
During the nine months ended March 31, 2024, we incurred $9.4 million in capital expenditures, a majority of which was spent at the Chaveroo Field where we participated in the drilling and completion of three gross (1.5 net) wells. First production on the three gross wells at Chaveroo Field occurred at the beginning of February 2024. During the first fiscal quarter of 2024, we also participated in the drilling and completion of two new wells in the Delhi Field. Production of the Delhi wells came online in the first fiscal quarter of 2024 and produced consistently in the second fiscal quarter.
Previous wording
Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2024, we expect budgeted capital expenditures to be in the range of $10.0 million to $14.0 million, which excludes any potential acquisitions. Our expected capital expenditures for fiscal year 2024 include the two new drilled wells at Delhi Field and three wells at Chaveroo Field, both of which are discussed above. We also expect to start incurring capital expenditures, in the fourth quarter at Chaveroo Field, for the second development block consisting of six horizontal wells. As mentioned inRecent Developments, the Company has entered into three separate definitive agreements to purchase oil and natural gas properties in the SCOOP/STACK plays in central Oklahoma for a combined purchase price of $43.5 million, before customary closing adjustments. Our budgeted capital expenditures discussed above do not include any potential capital projects associated with properties in the SCOOP/STACK Acquisitions.
Current wording
Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2024, we expect budgeted capital expenditures to be in the range of $10.0 million to $12.0 million, which excludes any potential acquisitions. Our expected capital expenditures for fiscal year 2024 include the two new drilled wells at Delhi Field and three wells at Chaveroo Field, both of which are discussed above. As mentioned inRecent Developments, we closed three separate definitive agreements to purchase oil and natural gas properties in the SCOOP/STACK plays in central Oklahoma for a combined purchase price of $40.5 million after taking into account preliminary post-close adjustments. Our budgeted capital expenditures discussed above also include capital projects associated with properties acquired in the SCOOP/STACK Acquisitions.
Previous wording
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 December 31, 2023 were $78.21 per barrel of oil, $2.63 per MMBtu of natural gas and $31.57 per barrel of NGLs. As of December 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 December 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. Additionally, a 10% reduction in respective commodity prices at December 31, 2023, while all other factors remained constant, would not have generated an impairment.
Current wording
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, 2024 were $77.64 per barrel of oil, $2.44 per MMBtu of natural gas and $29.88 per barrel of NGLs. As of March 31, 2024, 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, 2024 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. Additionally, a 10% reduction in respective commodity prices at March 31, 2024, while all other factors remained constant, would not have generated an impairment.
Previous wording
Cash provided by operating activities for the six months ended December 31, 2023 decreased $16.4 million compared to the six months ended December 31, 2022 primarily due to a decrease in revenues. Total revenues decreased $31.8 million as compared to the prior year period primarily due to lower commodity prices coupled with lower sales volumes. Our average realized price per barrel of oil equivalent (“BOE”) decreased $18.37, or 34.1% from the prior year period. Refer to*“Results of Operations”* below for further information.
Current wording
Cash provided by operating activities for the nine months ended March 31, 2024 decreased $37.0 million compared to the nine months ended March 31, 2023 primarily due to a decrease in revenues. Total revenues decreased $45.7 million as compared to the prior year period primarily due to lower commodity prices coupled with lower sales volumes. Our
Previous wording
Cash used in investing activities for the six months ended December 31, 2023 increased $2.8 million compared to the six months ended December 31, 2022 due to an increase in capital expenditures related to the drilling and completion of three new wells in the Chaveroo Field during the current quarter.
Current wording
Cash used in investing activities for the nine months ended March 31, 2024 increased $47.9 million compared to the nine months ended March 31, 2023 primarily due to the acquisition of our SCOOP/STACK properties in February 2024 together with an increase in capital expenditures related to the drilling and completion of three new wells in the Chaveroo Field. As of the quarter ended March 31, 2024, we have paid approximately $43.8 million for the SCOOP/STACK Acquisitions and have accrued estimated preliminary purchase price adjustments of $3.3 million related to net cash flows earned on the properties from the effective date to the closing date to arrive a net purchase price of $40.5 million.
Previous wording
Net cash flows used in financing activities for the six months ended December 31, 2023 decreased $21.2 million from the six months ended December 31,2022. In the prior year period, we had repayments totaling $21.3 million of borrowings outstanding under our Senior Secured Credit Facility. For the six months ended December 31, 2023 and 2022, cash dividends paid to our common stockholders were $8.0 million and $8.1 million, respectively.
Current wording
Net cash flows provided by financing activities for the nine months ended March 31, 2024 were $29.4 million compared to net cash flows used in financing activities of $37.3 million for the nine months ended March 31,2023. In the current year period, we borrowed $42.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions which was partially offset by $12.0 million cash dividends paid to our common stockholders together with $0.8 million paid to repurchase shares of common stock under our share repurchase plan. In the prior year period, we had repayments totaling $21.3 million of borrowings outstanding under our Senior Secured Credit Facility, $12.1 million in cash dividends paid to our common stockholders and$3.9 million paid to repurchase shares of common stock under our share repurchase program.
Rearranged current paragraphs (3)
Current report — wording carried from elsewhere
Dakota. The properties are operated by Foundation Energy Management, an established operator in the geographic region.
Current report — wording carried from elsewhere
On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among other things, extended the maturity of our Senior Secured Credit Facility to April 9, 2026, converted our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modified the Margined Collateral
Current report — wording carried from elsewhere
average realized price per barrel of oil equivalent (“BOE”) decreased $19.71, or 35.8% from the prior year period. Refer to*“Results of Operations”* below for further information.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
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.