ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with other sections of this Annual Report, including but not limited to "Forward-Looking Statements", Part 1. Item 1A Risk Factors, and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of this Annual Report.
The Company historically prepared its consolidated financial statements under International Financial Reporting Standards. For the year ended and as at December 31, 2022 the consolidated financial statements of the Company and its subsidiaries have been prepared in conformity with accounting principles generally accepted in the United States of America ("US GAAP"). US GAAP has been applied retrospectively.
This section of our Annual Report discusses 2022 and 2021 items and year-over-year comparisons between those periods. Amounts are stated in US dollars unless otherwise noted.
OVERVIEW AND HIGHLIGHTS
The Company is a U.S. oil and natural gas development company focused on maximizing return on equity. The Company has focused its drilling activity in two main areas, the Austin Chalk and Eagle Ford formations in the Giddings Field in Austin, Fayette, Lee, Robertson and Washington Counties, TX (the "Giddings Assets") and the Hawkville Field in Webb and LaSalle Counties, TX (the "Hawkville Assets").
For future periods, the Company plans to continue to develop its existing and adjacent footprint over the next several years while also evaluating additional development projects that fit its investment criteria.
As of December 31, 2022, the Company's assets consisted of a total leasehold position of 432,477 gross and 312,910 net acres, including the Hawkville area, the Giddings area, and the Holbrook Basin area, as follows:
• Giddings Assets: (a) in the Austin Chalk area include 9,004 gross and 7,583 net acres, and (b) in the Eagle Ford area include 134,198 gross and 16,104 net acres.
• Hawkville Assets: include 14,364 gross and 14,313 net acres.
• The Holbrook basin assets are located in Apache, Navajo and Coconino Counties, Arizona, and include 274,911 gross and net acres. Development of these assets for Helium is pending further research and planning.
2022 Highlights
• Oil and natural gas sales (net of royalties) of $195.6 million for the year ended December 31, 2022 (December 31, 2021 - $70.8 million).
• Reported net income and comprehensive income of $44.4 million for the year ended December 31, 2022 (December 31, 2021 - loss of $32.6 million). Adjusted EBITDA 1 (defined below) of $140.1 million for the same period (December 31, 2021 - $46.2 million).
• Reported net income and comprehensive income attributable to the Company's common shareholders of $7.4 million for the year ended December 31, 2022 (December 31, 2021 - loss of $32.3 million)
• 18 new wells were brought onto production during 2022.
• For the three months ended December 31, 2022, Alpine had 30.9 net wells (37 gross wells) with a net production rate of 14,445 BOE per day (gross production rate of 22,588 BOE per day).
• Average net production per day of 10,513 BOE during 2022 (gross production rate of 16,145 BOE per day) an increase of 156% year over year due to extensive drilling activity.
• Development projects continued to be funded via the development partnership structures, to facilitate continued drilling initiatives.
5 This is a non-GAAP financial measure. Refer to the “Non-GAAP Financial Measures” section for further information and the detailed reconciliation to the most directly comparable measure under GAAP.
• Entered into the ABS Facility for total borrowings of $135 million. As of December 31, 2022, approximately $110 million was outstanding on the ABS Facility.
• Expanded the size of the Corporate Credit Facility to a maximum size of $65 million. As of December 31, 2022 $41.5 million was drawn under the Corporate Credit Facility.
• Listing on the Nasdaq Stock Market of the Company's Class A Subordinate Voting Shares on September 28, 2022, trading under the ticker symbol "ALPS".
• Implemented a dividend distribution policy, starting January 2022, where monthly dividends of $0.03 per share for each of the subordinated voting shares and proportionate voting shares and $3.00 per each share of the multiple voting shares were declared each month, with aggregate dividends declared and paid in 2022 of $12,416,759 (2021 - $nil).
Subsequent Event Highlights
• The Company continued with its monthly dividend program, $0.03 per SVS ($3.00 per MVS and $0.03 per PVS) for January and February 2023.
• On January 20, 2023, the Company successfully completed the payout and liquidation of its development partnership five and concurrently formed development partnership seven.
• On February 23, 2023, the Company announced the suspension of the monthly dividend payments commencing in March 2023.
• The Company announced the commencement of a strategic review of assets on February 23, 2023.
• On March 3, 2023, the Company announced the resignation of Darren Tangen from the Board of Directors and subsequent hiring of James Russo as his replacement.
• On March 8, 2023, the Company announced the hiring of Stephens Inc. as its financial advisor to pursue an asset sale.
• In March 2023, the Company received covenant waivers on the Corporate Credit Facility and the ABS Facility until July 1, 2023 for potential future covenant breaches.
Oil and Natural Gas Reserves
The Company's year-end reserve evaluation as of January 1, 2023, was prepared by W.D. VonGonten & Co. in a report dated February 3, 2023 (the "Reserves Report"). The Reserve Report evaluates all of the Company's oil, natural gas, and NGL reserves, and uses pricing estimates in accordance with guidelines established by the United States Securities and Exchange Commission. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions.
Highlights of the Reserves Report include:
• Proved developed producing reserves (“PDP”) were 15.8 million BOE and total proved reserves (“1P”) were 24.0 million BOE.
• The PDP reserves have a composition of 24% oil and 76% natural gas and NGL, whereas the 1P reserves were composed of 18% oil and 82% natural gas and NGL.
• Net future development costs were $4.0 million for PDP and $75.5 million for 1P.
For details on the reserves data and estimates, as well as changes, refer to Item 8. Financial Statements and Supplementary Data - Supplemental Oil and Gas Information (Unaudited).
OPERATIONAL AND FINANCIAL RESULTS
Net Oil and Gas Revenues
For the year ended December 31,
Oil
Natural gas
NGLs
Total
% of total oil and gas revenue by product type:
Oil weighting
Natural gas weighting
NGL weighting
Our revenues vary from year to year primarily as a result of changes in commodity prices and production volumes. In 2022, oil and gas revenues increased by $124,852,168, an increase of 176.4% from 2021, driven by an 155.7% increase in production volumes and an increase in the average per BOE realized selling price of 8.1%, excluding the effect of commodity derivatives.
Production volumes:
The higher production in 2022 is a result of the addition of 18 new wells, with a primary focus on Hawkville gas wells attributing to the change in sales mix.
The production for the years ended December 31, 2022 and 2021, reflecting the Company's working interests and net of royalties, are as follows:
Year ended December 31,
% Change
Production:
Oil (bbl)
Natural gas (Mcf)
NGLs (bbl)
Total BOE 1
Average Daily Production:
Oil (bbl/d)
Natural gas (Mcf/d)
NGLs (bbl/d)
Total BOE 1 per day
Production Weighting on a BOE basis:
Oil
Natural gas
NGL
1 Natural gas is converted to a barrel of oil equivalent ("BOE") at the rate of one barrel equaling six Mcf (defined as one thousand cubic feet) based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
Average sales price:
On a per-BOE basis, the Company's average realized price for the year ended December 31, 2022 increased compared to the same period of 2021 by $3.82 per BOE, reflecting a 8.1% increase. The increase in sales prices is primarily due to the increase in the commodity price indices for oil, natural gas, and NGL. However, the realized average sales price per BOE also reflects the increased production of natural gas and NGLs at a lower overall per BOE price.
The average realized sales prices for the years ended December 31, 2022 and 2021, are as follows:
For the year ended December 31,
% Change
Oil - Bbl
Natural gas - Mcf
NGL - Bbl
Average sales price per BOE
Commodity Derivative Instruments
The future results of the Company's oil and natural gas operations will be affected by market prices of oil and natural gas which is affected by numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and natural gas liquid products, economic disruptions, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.
The Company enters into various commodity price derivative instruments to manage the price risk attributable to part of its future production. As the Company's derivatives are not designated for hedge accounting, the changes in fair value of the derivatives are recognized in income (loss) each period, creating earnings volatility in connection with outstanding derivatives. As commodity prices increase or decrease, such changes will have the opposite effect on the fair value of the derivatives.
At December 31, 2022, the net fair value of the open commodity derivatives was an asset position of $3,077,079 (2021 - liability position of $20,424,601). The change from 2021 is primarily due to the volume of outstanding derivatives as well as changes in the forward commodity prices relatively to the fixed price of the derivatives.
The Company's net loss on commodity derivatives for the year ended December 31, 2022 was $10,023,495 (2021 - $33,525,453). This amount consists of an unrealized gain of $26,246,351 (2021 - loss of $15,903,217) and realized losses of $36,269,846 million (2021 - loss of $17,622,236).
Refer to Note 18 of the financial statements for additional details.
Management of cash flow variability is an integral component of the Company's business strategy. Business conditions are monitored regularly and reviewed by the Company to establish risk management guidelines in carrying out the Company's strategic risk management program.
Expenses
The following table summarizes the Company's expenses and other income (expenses) for the periods indicated:sss
For the year ended December 31,
Expenses:
Production costs and transportation
General and administrative
Depletion and depreciation
Asset retirement obligation accretion
Total expenses
Operating Income
Other income (expenses)
Finance and interest expense
Acquisition costs
Income (loss) before income taxes
Deferred income tax provision (benefit)
Net income (loss) and comprehensive income (loss)
Net income attributable to redeemable non-controlling interest
Net income (loss) attributable to non-controlling interest
Net income (loss) attributable to the Company
Select Expenses per BOE:
Production costs and transportation
General and administrative
Depletion and depreciation
Finance and interest expense
Production and Transportation Costs
Total production and transportation costs for the year ended December 31, 2022, increased by $29,408,486, an increase of 243% when compared to the same period of 2021, primarily due to the overall increased production noted above. On a per BOE basis, the production and transportation costs increased by $2.76, an increase of 34%, due to higher operating costs for wells brought online in 2022, primarily relating to higher water disposal, fuel, and trucking costs, as well as overall market increases for service costs. The higher service costs are mainly due to inflation and market availability.
General and Administrative Costs
General and administrative costs for the year ended December 31, 2022, remained relatively consistent with an increase of $1,069,043 or 4%, when compared to the same period of 2021. This increase was primarily due to an increase in employee salaries and benefits of $3,709,863, an increase in professional, legal and advisory costs of $1,042,547, and office and administrative costs of $735,312, as well as increases in other items such as software, and lease expenses, and partially offset by the reduction to stock-based compensation of $4,281,056. From a per BOE perspective, the general and administrative costs reduced by $9.87 per BOE, a reduction of 59%, as a result of increased production levels noted above.
Depreciation, Depletion, and Amortization
The depreciation, depletion, and amortization expense consist of depletion on the Company's evaluated oil and gas properties. Depletion expense increased for the year ended December 31, 2022, by $38,584,756, an increase of 164% as compared to the same period of 2021 due to an increase in production, as well as an increase in the evaluated properties that are part of the depletion base. Depletion expense on a BOE basis also increased by $0.52 per BOE, an increase of 3%, reflecting the higher costs incurred on the new wells, due to inflation and market availability.
Finance and Interest Expense
Finance and interest expense for the year ended December 31, 2022, increased by $7,700,789, an increase of 134%, as compared to the same period of 2021 due to the increase in overall borrowings. The main increase relates to the financing and interest costs on the ABS Facility, as well as the Corporate Credit Facility, as defined in the financial statements. On a per BOE basis, the finance and interest expense has decreased by $0.32 per BOE, a decrease of 8%, due to the increased production in 2022.
Income Tax Expense (Benefit)
For the year ended December 31,2022, the Company recognized an income tax benefit of $1,928,319, resulting in an effective tax benefit of 4.5%, compared to an income tax expense of $1,928,319 for the year ended December 31, 2021, resulting in an effective tax rate of 5.9%. The overall change in the Company’s effective tax rate for the year ended December 31, 2022, from the previous year is primarily due to: (i) changes in amounts of income (loss) not subject to corporate tax and, (ii) current year activity causing the reversal of a previously recorded deferred tax expense resulting from temporary differences in recognition of items related to cost recovery of oil and natural gas properties.
Additionally, the Company assesses the likelihood that its deferred tax assets will be recovered from future taxable income and, to the extent it believes that recovery is more likely than not, it does not establish a valuation allowance reserve against the recorded net deferred tax assets. As of December 31, 2022, the Company recorded a valuation allowance on its net deferred tax assets after reflecting the reversal of previously recorded deferred tax liabilities due to current year activity. Refer to Note 15 of the financial statements for additional details.
Non-GAAP Financial Measures:
Within this report, references are made to terms which are not recognized under GAAP. Specifically, "field operating netbacks", "adjusted EBITDA", and measurements "per commodity unit" and "per BOE" do not have any standardized meaning as prescribed by GAAP and are regarded as non-GAAP measures. These non-GAAP measures may not be comparable to the calculation of similar amounts for other entities and readers are cautioned that use of such measures to compare enterprises may not be valid. The Company's management uses these non-GAAP supplemental measures to benchmark operations against prior periods and peer group companies and believes they provide useful supplemental information that can be used by investors, lenders, analysts and other parties to analyze the Company's performance and financial results.
Field Operating Netbacks
Field operating netbacks are used by management to assess operational performance of assets. Field operating netbacks are calculated by deducting depletion and commodity derivatives from the gross margin and is presented on a per BOE basis.
The Field Operating Netback for the years ended December 31, 2022 and 2021 are as follows:
For the year ended December 31,
Revenue from product sales
Gain/(loss) on derivative instruments
Less: Production costs and transportation
Less: Depreciation, depletion and amortization
Gross margin
Remove: Gain/(loss) on derivative instruments
R emove: Depreciation, depletion and amortizatio n
Field operating netback - total
Field operating netback - per BOE
For the year ended December 31, 2022, the Field Operating Netback per BOE remained relatively consistent, with an increase of $1.06 per BOE when compared to 2021. This reflects an offset of the $2.76 per BOE increase in production costs and transportation, with the increase in the average realized sales price per BOE of $3.82.
Adjusted EBITDA
Adjusted earnings before interest, taxes, depletion and amortization (“Adjusted EBITDA”), is a non-GAAP measure that is used to supplement the Company’s reported financial performance or position. The Company believes that Adjusted EBITDA, considered along with net earnings (loss), is a relevant indicator of trends relating to our operating performance and provides management and investors with additional information for comparison of our operating results to the operating results of other companies. All figures presented do not reflect any potential impact of non-controlling interests or redeemable non-controlling interests. The Company’s calculation of Adjusted EBITDA is net income/(loss) adding back finance and interest expense, depletion and depreciation, impairment, gains/losses on commodity derivatives, and non-recurring costs.
The following table provides a reconciliation of net income/(loss) before redeemable non-controlling interest and non-controlling interest to Adjusted EBITDA:
Year ended December 31,
Net income/(loss):
(+) Depreciation, depletion, and amortization expense
(+) Finance and interest expense
(+) Stock based compensation expense
(+) Acquisition cost s
(+) Derivative commodity contract (gains)/losse s
Adjusted EBITDA
FINANCING, LIQUIDITY AND CAPITAL RESOURCES
Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs that maintain and increase production and reserves, to acquire strategic oil and gas assets, to repay current liabilities and debt and ultimately to provide a return to shareholders. The Company's capital programs are funded by existing working capital, various lending facilities and redeemable non-controlling interests (discussed below) and cash provided from operating activities. Fluctuations in commodity prices, product demand, interest rates and various other risks may impact capital resources and capital expenditures.
During 2022, the main financing related transactions included the following:
• Asset backed securitization facility (the "ABS Facility"):
The Company entered into two tranches of borrowings under the ABS Facility, for a total size of $135 million.
On April 27, 2022, Tranche 1 of the ABS Facility was drawn for $80 million and carries an interest rate of LIBOR+6% (with a 1% LIBOR floor) for the initial year, LIBOR +12% for the second year. Tranche 1 has an initial maturity date of one year, with the Company having the option to extend an additional year to an ultimate maturity date of April 2024.
On September 12, 2022, Tranche 2 of the ABS Facility was drawn for an additional $55 million and carries an interest rate of LIBOR+8% (with a 1% LIBOR floor) for the initial year, LIBOR +14% for the second year. Tranche 2 has an initial maturity date of one year, with the Company having the option to extend an additional year to an ultimate maturity date of September 2024.
All borrowings under the ABS Facility are secured by working interests in a subset of the Company's producing assets.
As at December 31, 2022, the Company had $109,982,677 of principal outstanding under the ABS Facility.
• Corporate Credit Facility:
During the first quarter of 2022, the Company replaced its previous credit facility, which had a $12,500,000 borrowing capacity. The new corporate credit facility had a borrowing capacity of $30,000,000, which was subsequently increased in October 2022 to $65,000,000, subject to quarterly borrowing base determinations by the lender. The facility charges interest at prime +2.25% and had a one-year maturity. A subset of certain Company working interests in producing assets have been secured in connection with the Corporate Credit Facility.
As at December 31, 2022, the Company ad drawn $41,500,000 under the Corporate Credit Facility (2021 - $2,200,000). The borrowing base as at December 31, 2022 was $64,435,764 (2021- $6,579,750).
• Goldman Facility
The Company had borrowings under a credit facility with Goldman Sachs (the "Goldman Facility"), which carried an interest rate of LIBOR+6% (with a 1% LIBOR floor) and a maturity date of December 22, 2031. All borrowings under the Goldman Facility were secured by the Company's oil and gas producing wells as well as all assets of three of the Company's subsidiaries.
In April 2022, in connection with the ABS Facility (above), the Company repaid the Goldman Facility in full. The principal borrowing under this facility as at December 31, 2022 was $nil (2021 - $25,237,409).
• Asset Backed Preferred Instruments:
The Company had previously issued mandatorily redeemable instruments as part of a share buy-back structure. These instruments were fully repaid and settled in 2022.
• Development Partnerships:
The Company utilizes development partnerships as a mechanism to partially finance its development projects and activities. As part of the development partnerships, investors will provide funding to be used for the development of specific wells, in return, the investors will receive partnership units that provide a specified return, plus participation in the residual of those wells that can be realized via redemption.
Due to the redemption feature, the development partnership interests issued to external investors are accounted for as redeemable non-controlling interest.
For the year ended December 31, 2022, the redeemable non-controlling interests provided cash inflows of $53,728,933 (2021 - $41,042,693), and cash outflows for the distribution and settlement of $10,369,504 (2021 - $6,388,870). Of the total redeemable non-controlling interest that received distributions and/or was settled, the remaining non-cash balance related to settlements via the issuance of redeemable non-controlling interests for a new development partnership, via non-controlling interest shares, or via oil and gas property dispositions
As at December 31, 2022, the redemption value of the redeemable non-controlling interest was $107,583,737 (2021 - $46,552,839).
Refer to Note 2 and Note 9 of the financial statements for additional details.
Working Capital and Liquidity Risk
Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with the financial liabilities as they become due.
At December 31, 2022 the Company had a working capital deficit of $162,980,101, compared to a deficit of $36,148,466 as at December 31, 2021. Current assets increased by $12,104,044 compared to 2021, primarily due to an increase in accounts receivables due to higher oil and gas revenues, as well as increases in restricted cash and derivative assets, and partially offset by a reduction in cash and cash equivalents. This was offset by an increase in current liabilities of $138,935,679 primarily due to increases in accounts payable and accrued liabilities as well as current portions of borrowings, due to increased capital expenditures on oil and natural gas properties, and partially offset by a reduction to the current portion of the derivative liabilities.
Due to the working capital deficit, the Company does not currently have the cash resources to meet its current liabilities for the next twelve months. These factors raise substantial doubt about the Company's ability to continue as a going concern.
The Company's ability to continue as a going concern is dependent on its ability to generate sufficient cash flows from operations, as well as its ability to obtain financing via an asset sale and/or the issuances of debt and/or equity in the short term. While the Company believes it has sufficient forecasted funds to meet foreseeable obligations, there can be no assurance that the Company will be successful in its efforts to raise additional funds in the short term and its ability to generate sufficient operating cash flows.
Due to these factors, the Company may be unable to continue as a going concern. The financial statements do not include any adjustments related to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might be necessary should the Company be unable to continue as a going concern, and such adjustments could be material.
In an effort to increase liquidity, the Company has during and subsequent to the year ended December 31, 2022: (i) continued its drilling program to bring wells online and to increase cash flows from operating activities, (ii) raised funds through development partnerships, (iii) entered into a strategic review of assets and engaged Stephens Inc. for a potential asset sale, (iv) commenced the suspension of monthly dividends starting March 2023, (v) obtained waivers for covenant breaches on the Corporate Credit Facility and ABS Facility until July 1, 2023 in the event of a covenant breach, and (vi) obtained an extension to the initial maturity date of the first tranche of the ABS Facility until July 1, 2023.
Sources and Uses of Cash
The Company's sources and uses of cash are summarized as follows:
For the year ended December 31,
Net cash from operating activities
Net cash used for investing activities
Net cash from financing activities
Net change in cash and cash equivalents and restricted cash
Cash Flows from Operating Activities
The net cash from operating activities in 2022 increased by $59,905,356, an increase of 182% from 2021. The increase was driven by the increase in production, as well as changes to working capital and timing of cash receipts and disbursements.
Cash Flows used for Investing Activities
During the year ended December 31, 2022, the Company’s cash flows used for investing activities increased by $155,532,335, an increased of 274% when compared to 2021, due to increased drilling and development of its oil and gas properties. For the evaluated oil and gas properties, the majority of the activity related to the drilling of horizontal wells in the Giddings and Hawkville Fields. The expenditures on unevaluated properties focused on the acquisition, exploration and development of those unevaluated assets.
Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity.
Cash Flows from Financing Activities
During the year ended December 31, 2022, cash provided by and used in financing activities increased by $91,769,372, an increase of 312% when compared to 2021, primarily due to the increased net borrowings under the external debt facilities, as well as increases in the net proceeds from the issuance of redeemable non-controlling interests.
The net cash proceeds from the debt issuances were in part offset by the use of cash for the payments of dividends of $18,969,442, to both the Company's common shareholders, and dividends paid to its non-controlling interest holders, as well as the use of $4,324,915 in cash to repurchase and cancel the Company's shares.
Refer to the statements of cash flows of the financial statements for further details.
Off-Balance-Sheet Arrangements
The Company does not have any special-purpose entities nor is it a party to any arrangements that would be excluded from the consolidated balance sheet.
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATES AND POLICIES
The Company's financial statements are prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP), which require management to make estimates, judgments and assumptions that affect the amounts reported in our financial statements and accompanying notes. Certain accounting policies are identified as critical because they require management to make judgments and estimates based on conditions and assumptions that are inherently uncertain, and because the estimates are of material magnitude to revenue, expenses, cash flows from operations, income or loss and/or other important financial results. These accounting policies could result in materially different results should the underlying conditions change or the assumptions prove incorrect.
We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates. See Note 2 to the financial statements in this Annual Report for further details on our accounting policies as at December 31, 2022.
Going Concern
The financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, realization of assets, and liquidation of liabilities in the normal course of business.
Oil and Natural Gas Properties
The Company uses the full-cost method of accounting for its oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company's activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, and general and administrative expenses directly related to acquisition, exploration and development activities, but does not include any costs related to production, selling or general corporate administrative activities.
In determining the depletion capitalized costs of oil and natural gas properties are amortized using the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus estimates of future development costs by estimates of proved reserves quantities. Unproved and unevaluated property costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are considered proved or impaired. The Company reviews its unproved and unevaluated properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization.
As a result, the determination of depletion can be significantly impacted by the costs identified as being part of the depletion base, and the proved reserves volumes and future development costs.
Similarly, the assessment of impairment of evaluated oil and gas properties is subject to the ceiling test. This ceiling test determines a limit, or ceiling, on the net capitalized costs of oil and natural gas properties. The net capitalized costs are limited to the lower of unamortized costs less related deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of: (a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) any income tax effects related to the properties involved.
Therefore, changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company's actual ceiling test computation and impairment analyses in future periods.
Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue
Engineers and technical staff prepare the estimates of oil and natural gas reserves and associated future net revenues. While the Company has proved, probable and possible reserves, the Company has elected to present only proved reserves in this report. Proved reserves are defined as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time.
The assessment of reported recoverable quantities of proved reserves includes estimates regarding production volumes, commodity prices, remediation costs, timing and amount of future development costs, and production, transportation and marketing costs for future cash flows. It also requires interpretation of geological and geophysical models in anticipated recoveries. The economical, geological and technical factors used to estimate reserves may change from period to period. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect the future reserves estimates, financial condition, results of operations and cash flows. The Company cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future depletion of capitalized costs and result in an impairment of assets that may be material.
Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion and the ceiling test. The estimated present value of future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The associated commodity prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with guidelines established by the United States Securities and Exchange Commission. Under these guidelines, future net revenues are calculated using prices that represent the arithmetic averages of the first day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues.
The reserve assessment was completed by an external third-party engineering firm for the years ended December 31, 2022 and 2021 and reserves are internally updated for interim periods.
2023 OBJECTIVES AND OUTLOOK
During 2023, the Company plans on continuing to manage production of its primary assets in the Giddings and Hawkville fields. As previously disclosed, the Company expects to bring seven wells onto production by the end of the first quarter of 2023, with a pause in activity until the sales process is complete.
The Board has formed a sub-committee, led by independent directors, to lead discussions with the various stakeholders of the Company as it assesses alternatives following the conclusion of the sales process.
SUBSEQUENT EVENTS
Dividends
On January 3, 2023, the Company's board of directors (the "Board") declared a dividend of $0.0315 per SVS and PVS, and $3.15 per MVS. Payable on January 31, 2023, to shareholders of record on the close of business on January 17, 2023.
On February 1, 2023, the Company's Board declared a dividend of $0.0315 per SVS and PVS, and $3.15 per MVS. Payable on February 28, 2023, to shareholders of record on the close of business on February 14, 2023.
On February 23, 2023, it was announced that monthly dividends would be suspended beginning in March 2023, in connection with the strategic review of assets.
Completion of the Fifth Development Partnership and creation of Development Partnership Seven
On January 20, 2023, the Company redeemed redeemable non-controlling interests with a redemption value of $36,354,869. As part of this redemption, the development partnership five units with a redemption value of $2,505,631 were exchanged for 499,794 Class B non-voting units of the Company's operating subsidiary.
On January 20, 2023, the Company also formed the development partnership seven program, with 24 external limited partners and the Company's operating subsidiary as a limited partner and the general partner. The intention of the program is to finance the drilling and completion of five wells, with external partners funding approximately 60% and the Company funding 40%. The Company raised $34,262,236 from external limited partners of which $4,946,981 was raised from officers and directors of the Company.
Strategic Review of Assets
On February 23, 2023, the Company announced that the Board had commenced a strategic review of its assets. The Company is seeking to facilitate a timely and orderly response to unsolicited inquiries by other upstream oil and gas companies who have expressed interest in acquiring various assets of the Company.
Director Resignation
On March 3, 2023, the Company announced that Darren Tangen had resigned from its Board, including its Compensation, Audit and Operations and Reserves Committees, effective March 2, 2023. In connection with the resignation, James Russo was appointed as a member of the Board as well as a member of the Compensation, Audit and Operations and Reserves Committees to fill the vacancy created by Darren Tangen's resignation.
Engagement of Stephens Inc.
On March 8, 2023, the Company announced that it had engaged Stephens Inc. as its financial advisor to pursue an asset sale for various strategic, high producing assets recently developed and proven by the Company. Proceeds of such sale are expected to retire existing liabilities as well as place additional capital on the Company's balance sheet.
Debt Amendments and Covenant Waiver`
In March 2023, the Company received a waiver of all covenants on the Corporate Credit Facility until July 1, 2023, and received a waiver on certain covenants on the ABS Facility until July 1, 2023. The Company also received an extension on the initial maturity date of Tranche 1 under the ABS Facility until July 1, 2023. In the absence of a covenant waiver, a breach of the covenant would result in the Corporate Credit Facility and/or ABS Facility to be due on demand.
Additional Information
Additional information relating to the Company is contained in the Company's Form 10-K.
