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MarketScreener Homepage  >  Equities  >  OTC Bulletin Board - Other OTC  >  Royale Energy, Inc.    ROYL


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ROYALE ENERGY : Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-K)

03/30/2020 | 05:09pm EST

Global Pandemic

In December 2019 and continuing into 2020, there was a global outbreak of novel coronavirus that has resulted in changes in global supply and demand of certain mineral and energy products. While the direct and indirect negative impacts that may affect the Company cannot be determined, they could have a prospective material impact to the Company's operations, cash flows and liquidity.


The following discussion should be read in conjunction with Royale's Financial Statements and Notes thereto and other financial information relating to Royale included elsewhere in this document.

Since 1993, Royale has primarily acquired and developed producing and non-producing natural gas properties in California. In December 2018, Royale became the operator of a newly acquired field in Texas. The most significant factors affecting the results of operations are (i) changes in oil and natural gas price, production levels and reserves, and (ii) turnkey drilling activities, (iii) the increase in future cost associated with abandonment of wells.

Merger with Matrix Oil Management Corporation

On March 7, 2018, Royale, REF, and Matrix and its affiliates were notified by the California Secretary of State of the filing and acceptance of agreements of merger by the California Secretary of State, to complete the previously announced merger between the companies described in Item 1 - Description of Business - Merger with Matrix Oil Management Corporation.



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Joint Venture with RMX Resources, LLC

On April 4 and April 13, 2018, Royale contributed certain assets to RMX Resources, LLC pursuant to a Contribution Agreement described in Item 1 - Description of Business - Joint Venture with RMX Resources, LLC.

Critical Accounting Policies

Revenue Recognition

Royale's primary business is oil and gas production. Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines. Monthly, price data and daily production are used to invoice customers for amounts due to Royale and other working interest owners. Royale operates most of its own wells and receives industry standard operator fees. These Supervisory fees are recognized as a reduction to the company's General and Administrative expenses.

Royale generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.

Revenues from the production of oil and natural gas properties in which the Royale has an interest with other producers are recognized on the basis of Royale's net working interest. Differences between actual production and net working interest volumes are not significant.

Royale's financial statements include its pro rata ownership of wells. Royale usually sells a portion of the working interest in each well it drills or participates in to third party investors and retains a portion of the prospect for its own account. All results, successful or not, are included at its pro rata ownership amounts: revenue, expenses, assets, and liabilities as defined in FASB ASC 932-323-25 and 932-360.

The Company recorded amounts received from the Master Service Agreement ("MSA") with RMX for providing land, engineering, accounting and back-office support as part of revenues. Revenues earned under the MSA were recorded at the end of each month that services were performed in conformity with the Agreement with an offsetting receivable from the RMX joint venture. The service fee income was treated as earned at the end of each month that services were performed.

Equity Method Investments

Investments in entities over which the Company has significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents Royale's proportionate share of net income generated by the equity method. Equity method investments are included as noncurrent assets on the consolidated balance sheet.

Business Combinations

From time-to-time, the Company acquires businesses in the oil and gas industry. Businesses are included in the consolidated financial statements from the date of acquisition. We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction related costs as expense currently in the period in which they are incurred.

Fair value considerations include the evaluation of the underlying documentation supporting receivables, property, other assets and liabilities. If the documentation and support for a receivable or other asset represented by the seller is not deemed acceptable by the Company's auditors, the receivable or other asset is not considered in the purchase price until such time as the receivable or other asset can be proven to a level acceptable to the Company's auditors.



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Any receipts by the company of cash or other assets, subsequent to the transaction date for which the merger documentation was considered insufficient at the time of the merger, the company recognizes as a current liability. At such time as the documentation is deemed acceptable, the liability is relieved with a credit to earnings in the period of determination.

Oil and Gas Property and Equipment

Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.

The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets.

Royale uses the "successful efforts" method to account for its exploration and production activities. Under this method, Royale accumulates its proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalizes expenditures for productive wells. Royale amortizes the costs of productive wells under the unit-of-production method.

Royale carries, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where Royale is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred.

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves.

Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.

Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain Royale's wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Proved oil and gas properties held and used by Royale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

Royale estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated evaluation assumptions for crude oil commodity prices. Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on assumptions developed annually for evaluation purposes.

Impairment analyses are generally based on proved reserves. An asset group would be impaired if the undiscounted cash flows were less than its' carrying value. Impairments are measured by the amount the carrying value exceeds fair value. During 2019 and 2018, impairment losses of $977,682 and $1,183,515, respectively, were recorded on various capitalized lease and land costs where the carrying value exceeded the fair value or where the leases were no longer viable.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale expects to hold the properties. The valuation allowances are reviewed at least annually.



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Upon the sale or retirement of a complete field of a proved property, Royale eliminates the cost from its books, and the resultant gain or loss is recorded to Royale's Statement of Operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale's Statement of Operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should Royale's turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy its obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the "successful efforts" method.

Royale sponsors turnkey drilling agreement arrangements in properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete its obligations are incurred with any excess booked against its property account to reduce any basis in its own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs Royale incurs during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for its own account; and are recognized only upon making this determination after Royale's obligations have been fulfilled.

The contracts require the participants pay Royale the full contract price upon execution of the agreement. Royale completes the drilling activities typically between 10 and 30 days after drilling begins. The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for its proportionate share of operating costs. Royale retains legal title to the lease. The participants purchase a working interest directly in the well bore.

In these working interest arrangements, the participants are responsible for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for the cost of operations after drilling is completed.

Since the participant's interest in the prospect is limited to the well, and not the lease, the investor does not have a legal right to participate in additional wells drilled within the same lease. However, it is the Company's policy to offer to participants in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well with similar turnkey drilling agreement terms.

A certain portion of the turnkey drilling participant's funds received are non-refundable. The company records a liability for all funds invested as deferred drilling obligations until each individual well is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31, 2019 and 2018, Royale had deferred drilling obligations $5,232,675 of and $6,213,283 respectively.

If Royale is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included in cash and cash equivalents are amounts for use in completion of turnkey drilling programs in progress.

Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.


The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, plant products and gas reserve volumes and the future development costs. Actual results could differ from those estimates.

Deferred Income Taxes

Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. All available evidence, both positive and negative, must be considered to determine whether, based on the weight of that evidence, a valuation allowance for deferred tax assets is needed. The Company uses information about the Company's financial position and its results of operations for the current and preceding years.



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The Company must use its judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence is commensurate with the extent to which it can be objectively verified. The more negative evidence that exists, the more positive evidence is necessary and the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or all of the deferred tax asset. A cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome.

Future realization of a tax benefit sometimes will be expected for a portion, but not all, of a deferred tax asset, and the dividing line between the two portions may be unclear. In those circumstances, application of judgment based on a careful assessment of all available evidence is required to determine the portion of a deferred tax asset for which it is more likely than not a tax benefit will not be realized.

Going Concern

At December 31, 2019, the Company has an accumulated deficit of $73,387,738, a working capital deficiency of $3,425,012 and a stockholders' equity of $1,666,997 As a result, our financial statements include a "going concern qualification" reflecting substantial doubt as to our ability to continue as a going concern. See Note 1 to our audited financial statements. We have merged with Matrix to increase efficiency and reduce costs to both companies, thereby allowing a return to positive cash flow. We are exploring commitments to provide additional financing, but there is no guarantee that we will be able to secure additional financing on acceptable terms, or at all, if needed to fully fund our 2020 drilling budget and to support future operations.

Results of Operations for the Year Ended December 31, 2019, as Compared to the Year Ended December 31, 2018

The merger between Royale Energy and Matrix Oil Management was completed during the first quarter of 2018. For the year ended 2018, the consolidated amounts represented here are for the full year for Royale Energy, Inc. and the ten month period for Matrix Oil Management and its subsidiaries.

For the year ended December 31, 2019, we had a net loss of $348,383 compared to the net loss of $23,504,327 during the year in 2018. The table below reflects the major components of other income and expense.

Loss from Operations                          $ (845,071 )$  (3,204,056 )

Other Income (Expense):
Interest Expense                                 (20,559 )        (177,171 )

Gain (Loss) on Investment in Joint Venture (397,936 ) 333,931 Gain on Settlement of Payables

                   897,708           287,134
Other Gain                                       172,523                 -
Loss on Hedging Activities                             -          (105,130 )
Loss on Issuance of Stock Warrants                     -        (1,439,990 )
Loss on Sale of Assets, net                     (155,048 )     (19,199,045 )
Loss Before Income Tax Expense                $ (348,383 )$ (23,504,327 )

In 2019, the majority of the net loss resulted from a loss from operations of $845,071. In 2018, the majority of the loss on sale of assets of $20,092,402 was recorded upon the transfer of oil and gas properties to RMX and surface rights in exchange for cash and a 20 percent working interest in RMX under the Contribution Agreement, along with subsequent purchase price adjustments. This loss was offset by a $550,000 gain on the sale of seismic data and a $334,661 gain on the sale of previously owned Matrix leases. Under the Contribution Agreement, we also issued warrants to acquire 4,000,000 shares of Royale common stock and recorded a loss of $1,439,990. The gain on investment in joint venture of $333,931 represents Royale's share of RMX's net income from operations through the year ended December 31, 2018. See Note 2 - Formation of RMX and Asset Contribution.

During the year ended 2019, revenues from oil and gas production increased $729,913 or 45.6% to $2,329,275 from the 2018 revenues of $1,599,362. This increase was due to higher production volumes associated new wells placed in production in 2019 and the Jameson lease acquisition at the end of 2018. The net sales volume of oil for the year ended December 31, 2019 was 27,663 barrels of oil with an average price of $54.40 versus approximately 18,570 barrels with an average price of $64.10 per barrel, for the year in 2018. This represents an increase in net sales volume of 9,093 barrels or 49.0%. The net sales volume of natural gas for the year ended December 31, 2019, was approximately 292,472 Mcf with an average price of $2.82 per Mcf, versus 135,396 Mcf with an average price of $2.85 per Mcf for the year in 2018. This represents an increase in net sales volume of 157,076 Mcf or 116.0%. The increase in natural gas production volume was also due to an increase in production from new wells place into production in 2019 and the Jameson acquisition.



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Oil and natural gas lease operating expenses increased by $151,170 or 9.4%, to $1,764,538 for the year ended December 31, 2019, from $1,613,368 for the year in 2018. This was higher due to the increase in the number of wells operated by the Company during the year ended 2019, related the Jameson acquisition in the fourth quarter of 2018 and the 2019 drilling. When measuring lease operating costs on a production or lifting cost basis, in 2019, the $1,764,538 equates to a $3.85 per Mcfe lifting cost versus a $6.54 per Mcfe lifting cost in 2018, a 41.1% decrease, due to increased production from new wells placed into production in 2019.

The aggregate of supervisory fees and other income was $637,908 for year ended December 31, 2019, a decrease of $1,045,771 or 62.1% from $1,683,679 during the year in 2018. This decrease was mainly due to the loss of service agreement fees through an arrangement with RMX Resources, LLC.

Depreciation, depletion and amortization expense decreased to $468,143 from $722,935, an decrease of $254,792 or 35.2% for the year ended December 31, 2019, as compared to the year in 2018. The depletion rate is calculated using production by comparing capitalized cost to the recoverable reserves remaining. This decrease in depreciation expense was due to the increase in the number of wells and related equipment operated by the Company as compared to the estimated ultimate recovery, due to the fourth quarter 2018 Jameson acquisition and 2019 drilling.

General and administrative expenses decreased by $1,144,190 or 36.5% from $3,136,009 for the year ended December 31, 2018, to $1,991,819 for the year ended 2019. This decrease was primarily due to lower employee associated costs of approximately $368,000 and lower outside consulting of approximately $397,000 when compared to 2018, as the Company had fewer employees for the full year 2019 and utilized fewer outside consultants in 2019. Legal and accounting expense decreased to $751,935 for the year in 2019, compared to $1,391,037 for the year in 2018, a $639,102 or 45.9% decrease. This decrease was primarily due to lower legal and accounting fees related to the Matrix merger, which concluded during the first quarter of 2018. Marketing expense for the year ended December 31, 2019, increased $74,330, or 21.8%, to $414,971, compared to $340,641 for the year in 2018. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

At December 31, 2019, Royale Energy had a Deferred Drilling Obligation of $5,232,675. During 2019, we disposed of $11,961,767 of drilling obligations upon completing the drilling of eight natural gas wells and participating in the drilling of two oil wells in California, while incurring expenses of $9,051,859, resulting in a gain of $2,909,908. At December 31, 2018, Royale had a deferred drilling obligation of $6,213,283. During 2018, we disposed of $6,128,615 of obligations, upon completing the drilling of four natural gas wells, while incurring expenses of $3,569,899, resulting in a gain of $2,558,716.

During the first quarter in 2019, we recorded a loss on the sale of assets of $1,237,126 related a settlement agreement with RMX Resources, LLC, see Note 1, Settlement Agreement and Well Participation Agreement with RMX. During the fourth quarter of 2019, we recorded a gain of $1,254,204 on the settlement of contingent liabilities related to the merger with Matrix. During 2019, we recorded a $172,126 loss on the sale of leases obtained in the merger. During 2019, we recorded a gain on settlement of $834,736 on the reconciliation and settlement of royalties payable. During years ended December 31, 2019 and 2018, we recorded gains of $62,972 and $287,134, respectively, on the settlement of accounts payable. During 2019, we recorded geological and geophysical expense of $264,219 related mainly to the acquisition of a seismic survey of a Northern California field. During the years ended December 31, 2019 and 2018, we recorded a loss of $397,936 and a gain of $333,931, respectively on investment in joint venture as our 20% share of RMX Resources, LLC's 2019 net loss of $1,989,680 and 2018 net income of $1,669,655, respectively. During the year in 2019, we recorded a gain of $172,523 on the receipt of tax property tax refunds due to adjusted assessments on certain leases from prior years. We periodically review our proved properties for impairment on a field-by-field basis and charge impairments of value to the expense. During 2019 and 2018, we recorded lease impairments of $977,682 and $1,183,515, respectively on various lease and land costs that were no longer viable. During 2018, we recorded a $105,130 loss on derivative instruments, reflecting the period end market-to market changes in the fair value positions, related to Matrix operations prior to the conclusion of the merger. During the years in 2019 and 2018, we recorded write downs of $28,343 and $9,790, respectively on certain well equipment that was either written down to their current market value or were no longer useable.

Bad debt expense for 2019 and 2018 were $60,512 and $648,518, respectively. The expenses in 2019 and 2018 arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment and our year-end oil and natural gas reserve values. We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges appears doubtful. By contract, the Company may not collect some charges from its Direct Working Interest owners for certain wells that ceased production or had been sold during the year, to the extent that these charges exceed production revenue.

Interest expense decreased to $20,559 for the year ended December 31, 2019, from $177,171 in 2018, a $156,612 decrease. This decrease resulted from interest accrued on the term loan agreement originated by Matrix in 2018. Further details concerning this agreement can be found in Capital Resources and Liquidity, below.



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In 2019 and 2018, we did not have an income tax expense due to the use of a percentage depletion carryover valuation allowance created from the current and past operations resulting in an effective tax rate less than the new federal rate of 21% plus the relevant state rates (mostly California, 8.8%).

Capital Resources and Liquidity

At December 31, 2019, Royale had current assets totaling $8,712,314 and current liabilities totaling $12,137,325, a $3,425,012 working capital deficit. We had cash and cash equivalents at December 31, 2019 of $1,031,014 and restricted cash of $2,845,515 compared to cash and cash equivalents of $1,853,742 and restricted cash of $4,501,300 at December 31, 2018.

Ordinarily, we fund our operations and cash needs from our available credit and cash flows generated from operations. We believe there is some doubt that the company has the ability to meet liquidity demands through cash-flow from operations. . In that event, the Company will seek alternative capital sources through additional sales of equity or debt securities, or the sale of property.

At December 31, 2019, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $1,189,892, compared to $1,411,144 at December 31, 2018, a $221,252 decrease. This decrease was mainly due to receipts from an affiliate for contracted services. At December 31, 2019, revenue receivable was $589,151, an increase of $272,177, compared to $316,974 at December 31, 2018, due to higher oil and gas production volumes on wells that were drilled and came online in 2019. At December 31, 2019, our accounts payable and accrued expenses totaled $6,031,034, an increase of $1,135,501 from the accounts payable at December 31, 2018 of $4,895,533, mainly related to drilling at year end 2019 and operations related trade accounts payable.

Shortly before completion of the Merger, in February 2018, a $300,000 note and accrued interest of $47,500 was converted into 750,000 shares of Royale common stock valued at $347,500, and Royale agreed to a cash settlement with the holder of a $1,280,000 note for $1,900,000, which was paid on April 13, 2018.

The Company recognized $164,401 in interest expense for the period ended March 31, 2018, related to a term-loan held by Matrix Oil Management Corp at the time of merger. The loan balance as of March 31, 2018 was $11,140,749. In April 2018 pursuant to the Contribution Agreement, this loan agreement was paid in full.

We have not engaged in hedging activities nor do we use derivative instruments to manage market risks.

Operating Activities. For the years ended December 31, 2019 and 2018, cash used by operating activities totaled $3,250,120 and $2,865,829, respectively. This $384,291 or 13.4% increase in cash used was primarily due to higher prepaid expenses paid mainly to RMX for contracted services.

Investing Activities. Net cash provided by investing activities totaled $1,493,275 and $8,183,844, respectively for the years ended December 31, 2019 and 2018. During 2019, our turnkey drilling expenditures were higher, where we drilled eight natural gas wells and participated in the drilling of two oil wells, while in 2018 we drilled four natural gas wells and completed two. Additionally, in 2019 we received approximately $11 million in direct working interest turnkey drilling investments. The difference in cash during the year in 2018 was due to approximately $4 million in cash received in the merger and for the oil and gas asset sale and contribution in the formation of RMX Resources, LLC. In 2018, we also received $550,000 on the sale of a seismic license and approximately $412,000 for the sale of various lease interests previously owned by Matrix. During the year in 2018, we also received approximately $6.5 million in direct working interest investor turnkey drilling investments.

Financing Activities. Net cash used by financing activities totaled $721,668 and $2,301,666 for the years ended December 31, 2019 and 2018, respectively. During 2019, a financing agreement for a seismic survey was recognized when the terms were finalized, on which there were principal payments of approximately $186,012. Additionally, in 2019, there were principal payments of approximately $391,000 on our note with Forza Operating and payments of approximately $145,000 on our leasing obligations. During the period in 2018, we paid a $1.9 million settlement payment for the cash advances on pending transactions. During the period in 2018, we also paid approximately $275,000 for principal and fee payments on the Matrix originated term loan agreement. In 2018, we paid approximately $127,000 on a note payable to an industry partner for lease operating and plugging and abandonment costs.



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Changes in Reserve Estimates

During 2019, our overall proved developed and undeveloped natural gas reserves increased by 44.2% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately .89 million cubic feet of natural gas. This downward revision was mainly the result of a decrease in proved undeveloped natural gas reserves from drilling locations which the Company had contracted. See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-29.

During 2018, our overall proved developed and undeveloped reserves increased by 40.1% and our previously estimated proved developed and undeveloped reserve quantities were revised downward by approximately .40 million cubic feet of natural gas. This downward revision was mainly the result of one location with previously estimated proved undeveloped natural gas reserves which the Company had decided not to drill. See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-29.

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