Item 7. Management’s Discussion and Analysis
Item 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Report contains additional information that should be referred to when reviewing this material. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements.
Overview:
We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and non-producing
properties located primarily in Texas, and Oklahoma. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.
We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis.
Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all our derivative contracts are accounted for under mark-to-market
accounting, we expect continued volatility in gains and losses on mark-to-market
derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.
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Market Conditions and Commodity Prices:
Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. In addition, our realized prices are further impacted by our derivative and hedging activities. We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs. Index prices for oil, natural gas, and NGLs have improved since the lows of 2020 however we expect prices to remain volatile and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues.
Critical Accounting Estimates:
Proved Oil and Gas Reserves
Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.
Depreciation, Depletion and Amortization for Oil and Gas Properties
The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively. Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production
method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. The reserve base includes only proved developed reserves for lease and well equipment costs, which include development costs and successful exploration drilling costs. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
Liquidity and Capital Resources:
Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of acreage.
Net cash provided by operating activities for the year ended December 31, 2021 was $28.6 million, compared to $16.4 million in the prior year. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.
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Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives.
If our exploratory drilling results in significant new discoveries, we will have to expend additional capital to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing.
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2022 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures. We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices.
The Company maintains a Credit Agreement with a maturity date of February 11, 2023, providing for a credit facility totaling $300 million, with a borrowing base of $50 million. As of March 31, 2022, the Company has $9 million in outstanding borrowings and $41 million in availability under this facility. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a re-determined
estimate of proved oil and gas reserves. The next borrowing base review is scheduled for May 2022. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined
borrowing base.
Our credit agreement required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. Accordingly, the Company has in place the following swap agreements for oil and natural gas.
2022
2023
2022
2023
Swap Agreements
Natural Gas (MMBTU)
1,528,000
377,000
$
3.15
$
3.87
Oil (barrels)
530,600
114,200
$
66.20
$
74.07
The successful development of these reservoirs has proven-up
drilling locations on our nearby 2,600-acre
leasehold block in which the Company holds between 14% and 56% interest. It is anticipated that development of as many as 54 additional horizontal wells on this 2,600-acre
block will occur over the coming years. The cost of such development will be approximately $370 million with the Company’s share being approximately $170 million. The actual number of wells that will be drilled, the cost, and the timing of drilling will vary based upon many factors, including commodity market conditions.
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The Company is currently participating with SEM Operating Company, LLC in four horizontal wells in Irion County, Texas with 10.3% interest for an estimated investment of $2.35 million. These wells are expected to be online in the second quarter of 2022.
Additional Permian Basin development drilling plans in 2022 include the drilling of nine 2.5-mile
horizontal wells with BTA Oil Producers in Reagan County, Texas. The Company will have an average of 43.67 % interest in these wells with an expected capital outlay of $40.5 million through completion. These wells are scheduled to be drilled in June and completed in 2022.
Also in 2022, in the Permian Basin of West Texas, the Company plans to drill four horizontal wells with ConocoPhilips in Martin County with an average of 38% interest. The total capital expenditure for these wells is expected to be $15 million. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.
The Company maintains an acreage position of 17,148 gross (10,640 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties and we believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp that support the potential drilling of as many as 180 additional horizontal wells.
In 2021, in the Scoop/Stack Play of Oklahoma, the Company participated for 11.25% interest in the drilling of four wells and the completion of three of these wells in December that were placed on production in early January of 2022. The Company had an expenditure of approximately $2.2 million. In the first quarter of 2022, the Company received and approved proposals from Ovintiv Mid-Continent,
Inc. for the drilling of four horizontal wells in Canadian County, Oklahoma. Drilling will begin in April and completion of these wells are expected in June of this year. The Company will participate for 9.38% and expects total drilling and completion costs to be approximately $1.8 million.
In Oklahoma, the Company’s horizontal activity is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 200 net leasehold acres in the Scoop/Stack Play. We believe this acreage has significant additional resource potential that could support the drilling of as many as 54 new horizontal wells based on an estimate of six wells per section: two in the Mississippian and two in the Woodford Shale. Should we choose to participate in future development, our share of the capital expenditures would be approximately $36 million at an average 10% ownership level; the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest.
To supplement cash flow and finance our drilling program during 2021, the Company sold leasehold rights through one transaction in Texas, receiving gross proceeds of approximately $1.45 million in exchange for 116 net leasehold acres. In the first quarter of 2022, The Company sold 1,809 net leasehold acres in Regan and Midland Counties, Texas through two transactions receiving gross proceeds of $14.1 million and retaining certain over-riding royalty interests. These sales have allowed the Company to reduce its bank debt to $9 million, as of March 31, 2022, with the right to borrow up to $50 million under its current revolving line of credit.
The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.
The Company has a stock repurchase program in place, spending under this program in 2021 and 2020 was $145 thousand and $710 thousand, respectively. The Company expects continued spending under the stock repurchase program in 2022.
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Results of Operations:
2021 and 2020 Compared
We reported a net income of $2.1 million for 2021, or $1.05 per share, compared to a net loss of $2.3 million, or $1.16 per share for 2020. The current year net income reflects commodity price increases partially offset by losses related to the valuation of derivative instruments. The significant components of income and expense are discussed below.
Oil, NGL and gas sales
increased $36.1 million, or 97.6% to $73.1 million for the year ended December 31, 2021 from $37.0 million for the year ended December 31, 2020. Crude oil, NGL and natural gas sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices at the well head increased an average of $30.38 per barrel, or 79.9% on crude oil, increased an average of $15.75 per barrel, or 140.4% on NGL and increased $2.29 per Mcf, or 184.3% on natural gas during 2021 as compared to 2020.
Our crude oil production increased by 5,000 barrels, or 0.68% to 738,000 barrels for the year ended December 31, 2021 from 733,000 barrels for the year ended December 31, 2020. Our NGL production decreased by 21,000 or 4.85% to 416,000 for the year ended December 31, 2021 from 437,000 barrels for the year ended December 31, 2020. Our natural gas production decreased by 145 MMcf, or 4.29% to 3,236 MMcf for the year ended December 31, 2021 from 3,381 MMcf for the year ended December 31, 2020. The changes in crude oil, NGL and natural gas production volumes are a result of the natural decline of existing properties slightly offset by new wells placed in production.
The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2021 and 2020 (excluding realized gains and losses from derivatives).
Twelve months ended
December 31,
Increase /
(Decrease)
Increase /
(Decrease)
2021
2020
Barrels of Oil Produced
738,000
733,000
5,000
0.68
%
Average Price Received
$
68.39
$
38.02
$
30.38
79.91
%
Oil Revenue (In 000’s)
$
50,474
$
27,865
$
22,609
81.14
%
Mcf of Gas Sold
3,236,000
3,381,000
(145,000
)
(4.29
)%
Average Price Received
$
3.53
$
1.24
$
2.29
184.25
%
Gas Revenue (In 000’s)
$
11,432
$
4,202
$
7,230
172.06
%
Barrels of Natural Gas Liquids Sold
416,000
437,000
(21,000
)
(4.85
)%
Average Price Received
$
26.97
$
11.22
$
15.75
140.36
%
Natural Gas Liquids Revenue (In 000’s)
$
11,220
$
4,906
$
6,314
128.70
%
Total Oil & Gas Revenue (In 000’s)
$
73,126
$
36,973
$
36,153
97.78
%
Oil, Natural Gas and NGL Derivatives
We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market
adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market
accounting treatment creates volatility in our revenues.
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The following table summarizes the results of our derivative instruments for the twelve months ended December 2021 and 2020:
Twelve months ended
December 31,
2021
2020
Oil derivatives – realized (losses) gains
$
(3,212
)
$
5,697
Oil derivatives – unrealized (losses) gains
(4,055
)
161
Total (losses) gains on oil derivatives
$
(7,267
)
$
5,858
Natural gas derivatives – realized (losses) gains
(1,833
)
476
Natural gas derivatives – unrealized (losses)
(859
)
(351
)
Total (losses) gains on natural gas derivatives
$
(2,692
)
$
125
Total (losses) gains on oil and natural gas
$
(9,959
)
$
5,983
Prices received for the twelve months ended December 31, 2021 and 2020, respectively, including the impact of derivatives were:
2021
2020
Increase /
(Decrease)
Increase /
(Decrease)
Oil Price
$
64.04
$
45.79
$
18.25
39.9
%
Gas Price
$
2.97
$
1.38
$
1.58
114.4
%
NGL Price
$
26.97
$
11.22
$
15.75
140.4
%
Field service income
increased $0.7 million, or 6.3% to $11.8 million for the year ended December 31, 2021 from $11.1 million for the year ended December 31, 2020. This increase is a combined result of increased utilization and rates charged to customers as oil and gas prices improved during 2021. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.
Lease operating expenses
increased $4.8 million, or 20.9% to $27.8 million for the year ended December 31, 2021 from $23.0 million for the year ended December 31, 2020. This increase is primarily due to returning higher lifting cost properties to production during 2021 as commodity prices improved, combined with higher production taxes related to higher commodity prices.
Field service expense
increased $2.6 million, or 28.9% to $11.6 million for the year ended December 31, 2021 from $9.0 million for the year ended December 31, 2020. Field service expenses primarily consist of wages and vehicle operating expenses which have increased during 2021 related to increased utilization of our equipment services.
Depreciation, depletion, amortization and accretion on discounted liabilities
decreased $1.9 million, or 6.7% to $26.3 million for the year ended December 31, 2021 from $28.2 million for the year ended December 31, 2020. The DD&A expense is primarily attributable to our properties in West Texas and Oklahoma, reflecting the declining cost basis of those properties.
General and administrative expense
decreased $4.6 million, or 30.7% to $10.4 million for the year ended December 31, 2021 from $15.0 million for the year ended December 31, 2020. This decrease in 2021 reflects cost reductions put in place during 2020 responding to sharply lower commodity prices, primarily reductions in staff and compensation.
Gain on sale and exchange of assets
of $1.5 million for the year ended December 31, 2021 and $15.8 million for the year ended December 31, 2020 consists principally of sales of deep rights in undeveloped acreage in West Texas and, in 2020, also included the sale of marginal wells in West Virginia.
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Interest
expense increased $0.1 million, or 5.3% to $2.0 million for the year ended December 31, 2021 from $1.9 million for the year ended December 31, 2020. The average interest rate paid on outstanding bank borrowings under its revolving credit facility during 2021 and 2020 were
5.29% and 3.95%, respectively. As of December 31, 2021 and 2020, the total outstanding borrowings under its revolving credit facility were $36.0 million and $37.0 million, respectively.
Tax
expense of $2.5 million and tax benefit of $0.5 million were recorded for the years ended December 31, 2021 and 2020, respectively. The change in our income tax provision was primarily due to the increase in pre-tax
income for the year ended December 31, 2021.
Item 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are a smaller reporting company and therefore no response is required pursuant to this Item.
Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The consolidated financial statements and supplementary information included in this Report are described in the Index to Consolidated Financial Statements at Page F-1
of this Report.
Item 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.