PRIMEENERGY RESOURCES CORP - Quarter Report: 2021 June (Form 10-Q)

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10-Q

June 30, 2021

 

 

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– Unaudited

– Unaudited

– Unaudited

– Unaudited

As of June 30, 2021, PrimeEnergy’s significant accounting policies are consistent with those discussed in Note 1—Description of Operations and Significant Accounting Policies of its consolidated financial statements contained in PrimeEnergy’s Annual Report on Form for the fiscal year ended December 31, 2020. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.

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During May 2020, Prime Operating Company and Eastern Oil Well Services Corporation, subsidiaries of the Company received loan proceeds in the amount of $1.28 million and $0.47 million, respectively, under the Paycheck Protection Program (the “PPP”) of the CARES Act, which was enacted March 27, 2020. The PPP Loans are evidenced by a promissory note in favor of the Lender, which bears interest at the rate of 1.00% per annum. No payments of principal or interest are due under the note until the date on which the amount of loan forgiveness (if any) under the CARES Act, which can be up to 10 months after the end of the related notes covered period (which is defined as 24 weeks after the date of the loan) (the “Deferral Period”). The note may be prepaid at any time prior to maturity with no prepayment penalties. Funds from the PPP Loans may be used only for payroll and related costs, costs used to continue group health care benefits, mortgage payments, rent, utilities, and interest on other debt obligations that were incurred prior to February 15, 2020 (the “Qualifying Expenses”). Under the terms of the PPP Loans, certain amounts thereunder may be forgiven if they are used for Qualifying Expenses as described in and in compliance with the CARES Act. The Company utilized the PPP Loan proceeds exclusively for Qualifying Expenses during the coverage period and has submitted its application for forgiveness in accordance with the terms of the CARES Act and related guidance. In the event the PPP Loan or any portion thereof is forgiven, the amount forgiven is applied to the outstanding principal.

The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Leases assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average discount rate used was 5.5%. Certain leases may contain variable costs above the minimum required payments and are not included in the assets or liabilities. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded on the balance sheet.

In May 1989, stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At June 30, 2021 and 2020, remaining options held by two key executive officers on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.

The following table represents certain reserve and well information as of December 31, 2020.

 

In several of our producing regions, we have field service groups to service our operated wells and locations as well as third-party operators in the area. These services consist of well service support, site preparation, and construction services for drilling and workover operations. Our operations are performed utilizing workover and swab rigs, water transport trucks, hot oil trucks, saltwater disposal facilities, various land excavating equipment, and trucks we own and that are operated by our field employees.

Our development, exploitation, exploration, and production activities in the Gulf Coast region are primarily concentrated in southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet. We had 239 producing wells (124 net) in the Gulf Coast region as of December 31, 2020, of which 158 wells are operated by us. Average net daily production in our Gulf Coast Region in 2020 was 297 Boe. On December 31, 2020, we had 517 MBoe of proved reserves in the Gulf Coast region, which represented 5% of our total proved reserves. We maintain an acreage position of over 11,900 gross (4,300 net) acres in this region, primarily in Dimmit and Polk counties. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, nineteen water transport trucks, two saltwater disposal wells, two hot oilers, and excavating equipment. Services including well service support, site preparation, and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our operated wells and locations. As of June 30, 2021, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed, and no other related activities of material importance.

Region

Mid-Continent

Mid-Continent

Mid-Continent

Mid-Continent

Mid-Continent

Mid-Continent

year-end

Our West Texas activities are concentrated in the Permian Basin of West Texas and New Mexico. The basin covers more than 75,000 square miles and extends across 52 Counties. The Wolfcamp and Spraberry reservoirs of this basin are among the largest contiguous accumulations of oil and gas in the United States. Production from these reservoirs is West Texas Intermediate Sweet Crude oil and high quality casing-head gas. This region is managed from our office in Midland, Texas. As of December 31, 2020, we

 

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had 556 wells (263 net) in the West Texas area, of which 325 wells are operated by us. Principal producing intervals are in the Wolfcamp and Spraberry formations at depths ranging from 5,500 to 12,500 feet. The average net daily production in Our West Texas Region in 2020 was 3,178 Boe. On December 31, 2020, we had 8,242 MBoe of proved reserves in the West Texas area, or 79% of our total proved reserves. We maintain an acreage position of approximately 19,679 gross (12,461 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties, and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, four hot oiler trucks, one kill truck, and two roustabout trucks. Services including well service support, site preparation, and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our operated wells and locations.

In the spring of 2020, the Company participated with Apache Corporation in the drilling of six horizontal wells on our Kashmir acreage in Upton County, Texas. In March of 2021, we drilled an additional three wells on the same acreage block. As of June 30, 2021, the Company was participating in the completion of these nine horizontal wells for an average of 47.5% interest with an estimated total investment of approximately $27.8 million. As of August 23, 2021, all nine wells have been completed and are in the process of being placed on production.

year-end

All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:

 

 

year-end

year-end.

year-end,

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.

 

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We employ technologies to establish proven reserves that have demonstrated consistent results capable of repetition. The technologies being used in the estimation of our proved reserves include, but are not limited to, decline curve and volumetric analysis, analogy, geologic mapping, as well as evaluation of reservoir properties, production, and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2020, are summarized as follows (in thousands of dollars):

 

non-GAAP

non-controlling

In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also, in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.

While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.

Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $1.985 per MMBtu in 2020 as compared to $2.58 per MMBtu in 2019, and $3.10 per MMBtu in 2018. Oil prices, based on the NYMEX first of the month average price, were $39.57 per barrel in 2020 as compared to $55.69 per barrel in 2019, and $65.56 per barrel in 2018.

non-strategic

 

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3-mile

1,280-acre

965-acre

In Reagan County, Texas, the Company and Pioneer Natural Resources have agreed to jointly develop approximately 3,680 gross acres. This agreement facilitates the drilling of as many as 108 horizontal laterals where the company would have an average of 34.5% working interest and invest approximately $236 million. We believe this agreement represents significant future value for PrimeEnergy.

Also in Reagan County, Texas, the Company has separate joint development projects with BTA Producers, Inc. and Hibernia Energy III, LLC. These two development blocks can accommodate the drilling of 144 horizontal wells to produce from five prospective reservoirs, four of which are proven. The Company’s share is expected to be 50% and the potential investment net to the Company would be approximately $442 million. The actual number of wells eventually drilled, and the cost and the timing of such wells are dependent upon many factors including commodity market conditions.

2-mile

Mid-Continent

 

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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 six months ended June 30, 2021 was $11.4 million compared to $8.8 million for the same period of 2020. 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.

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 2021, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2021 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.

re-determined

re-determined

Our credit agreement requires us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. Accordingly, as of June 30, 2021, the Company has in place the following swap and put agreements for oil and natural gas.

 

The Company’s activities include development drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential. In 2016, based upon the results of horizontal wells and historical vertical well performance, we decided to reduce the number of vertical wells in our drilling program and focus primarily on horizontal well drilling. We believe horizontal development of our resource base provides superior returns relative to vertical development, due to the ability of horizontals to come in contact with and drain from a greater volume of reservoir rock over more acreage, with less infrastructure, and thus at a lower cost of development per acre.

Our primary focus is the development of our leasehold acreage in the Permian Basin of West Texas where the Company currently holds an acreage position of 19,680 gross (12,460 net) acres, the majority of which is in Reagan, Upton, Martin and Midland counties. We believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp, and can support the potential drilling of as many as 250 additional horizontal wells.

 

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The Middle Wolfcamp has been the primary target for production in the area until, however, in 2019, in Upton County, the Company drilled three horizontal wells with Apache Corporation targeting shallower reservoirs in the Wolfcamp “A”, the Jo Mill, and the Lower Spraberry. These three test wells proved the productive capability of these reservoirs for the 1,280 acre block in which they were drilled and led to the drilling of nine additional wells in early 2020 and the first quarter of 2021. As of August 23, 2021, all nine wells have been completed and are in the process of being placed on production. We have an average 47.5% interest in these wells and anticipated a total investment net to the Company of approximately $27.8 million.

3,260-acre

In Reagan County, Texas, the Company holds 12,700 Gross (8.870 net) acres with exceptional potential. Offset operators have proven the productive capability of four reservoirs from the Middle Wolfcamp to the Lower Spraberry. Here the Company could participate in as many as 352 horizontals with a net cost of approximately $890 million. Near-term development plans being discussed include the drilling of three 12,500’ laterals on one acreage block, and six horizontal laterals on a second acreage block with laterals from 7,500’ to 10,000’ in length. The Company’s share of these wells would average about 37.5% and cost approximately $35.2 million net.

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.

In Oklahoma, the Company’s horizontal activity is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,460 net leasehold acres with exceptional development potential. We believe this acreage could support the drilling of as many as 49 new horizontal wells based on an estimate of six wells per section: three in the Mississippian and three in the Woodford Shale. Should we choose to participate in future development, our share of the capital expenditures would be approximately $34 million at an average 10% ownership; otherwise the Company will sell its rights for cash, or cash plus a royalty or working interest.

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 in place both a stock repurchase program and a limited partnership interest repurchase program. Spending under these programs in 2020 was $1.45 million. The Company expects continued spending under these programs in 2021.

We reported net losses of $3.9 million, or $1.93 per share and $2.4 million, or $1.20 per share for the six and three months ended June 30, 2021, respectively, as compared to net losses of $6.4 million, or $3.23 per share and $6.3 million, or $3.14 per share for the six and three months ended June 30, 2020, respectively. Current year net income reflects decreases in production offset by commodity price increases over the three and six months ended June 30, 2021, fluctuations in gains related to the sale of assets and changes related to the valuation of derivative instruments. The significant components of income and expense are discussed below.

 

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The following tables summarizes the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2021 and 2020 (excluding realized gains and losses from derivatives).

 

 

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