What changed in this filing

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Item 1. Business

2022-04-21 compared with 2021-04-26 · 278 added, 458 removed, 97 unchanged (88% of the section changed)

PrimeEnergy Resources

Corporation (the Company) was organized in March, 1973, under the laws of the State of Delaware.

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.

All of our oil and

gas properties and interests are located in the United States.

Through our subsidiaries Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company, we act as operator and provide well-servicing support operations for many of

the onshore oil and gas wells in which we have an interest, as well as for third parties.

PrimeEnergy Resources Corporation (the “Company”) was organized in March, 1973, under the laws of the State of Delaware.

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.

All of our oil and gas properties and interests are located in the United States.

Through our subsidiaries Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company, we act as operator and provide well-servicing support operations for many of the onshore oil and gas wells in which we have an interest, as well as for third parties.

We are also active in the acquisition of producing oil and gas properties through joint ventures with industry partners.

Our subsidiary, PrimeEnergy Management

Corporation (PEMC), acts as the managing general partner of one oil and gas limited partnerships (the Partnerships), and acts as the managing trustee of one asset and income business trusts (the Trusts).

Exploration, Development and Recent Activities

The Company’s activities include development and exploratory drilling.

Our strategy is to develop the Companys extensive oil and gas

reserves primarily through horizontal drilling.

This strategy includes targeting reservoirs with high initial production rates and cash flow as well as targeting reservoirs with lower initial production rates but with higher expected return on

We believe that with todays technology, horizontal development of our reserves provides superior economic results as compared to vertical development, by delivering higher production rates through greater contact and stimulation of

a larger volume of reservoir rock while minimizing the surface footprint required to develop those same reserves.

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 current 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 non-strategic assets, or enter into strategic joint ventures.

In accordance with SEC rules governing the scheduling of development of proved undeveloped (PUD) reserves, our

year-end reserve report includes only those three wells that were slated to be drilled in 2021 along with 10 PUD locations that at year-end 2020 had been drilled but not

yet completed.

The three new wells drilled in the first quarter of 2021 and the six wells drilled in 2020 on the same Upton County, Texas tract are slated to be completed and on production by the end of the second quarter of 2021.

The Company has an

average of 47.5% interest in these nine wells.

The remaining four PUD horizontal wells, drilled but not completed at year-end, are located in Grady County, Oklahoma.

Of these, the Company has 10% interest in

one well and less than one percent interest in each of three wells.

Since the start of our West Texas horizontal drilling program in 2015

and through the first quarter of 2021 the Company has participated in 77 horizontal wells in the Permian Basin, one of which was drilled and brought into production in 2020.

As of year-end, the Company has

invested approximately $108 MM in this drilling program, including over $4 million in six wells drilled in 2020 that will be completed in 2021.

In addition, the Company has invested another $3.2 million in three new horizontals drilled in

the first quarter of 2021.

All nine of these wells are designated as proved undeveloped in the year-end reserve report and are to be completed and on-line by the end of

the second quarter of 2021.

Of the total 77 horizontal wells in this program, the Company has an average of 30.75% interest in 62 wells, and less than one percent interest in 15 wells.

Our strategy is to develop the Company’s extensive oil and gas reserves primarily through horizontal drilling.

This strategy includes targeting reservoirs with high initial production rates and cash flow as well as targeting reservoirs with lower initial production rates but with higher expected return on investment.

We believe that with today’s technology, horizontal development of our reserves provides superior economic results as compared to vertical development, by delivering higher production rates through greater contact and stimulation of a larger volume of reservoir rock while minimizing the surface footprint required to develop those same reserves.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy.

In 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

Our capital budget for the year is reflective of current 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 non-strategic

assets, or enter into strategic joint ventures.

In 2021, nine two-mile

horizontal wells operated by Apache in Upton County, Texas were completed in the third quarter of 2021 and three two-mile

horizontal wells operated by Ovintiv Mid-Continent

Inc, in Canadian County, Oklahoma were completed in the fourth quarter of 2021.

The Company has an average of 47.5% interest in the nine wells and 11.25% interest in the three wells completed with Ovintiv.

Since the start of our West Texas horizontal drilling program in 2015 and through the fourth quarter of 2021 the Company has participated in 77 horizontal wells in the Permian Basin, three of which were drilled in 2021 and, together with six other horizontals drilled in 2020, were completed and brought into production in late September or early October of 2021.

As of year-end,

the Company has invested approximately $129 MM in this drilling program.

All nine of the wells in this program completed in 2021, were previously designated as proved undeveloped in the 2020 year-end

reserves report.

Of the horizontal wells in this program, the Company has an average of 30.62% interest in 62 wells, and less than one percent interest in 15 wells.

In Upton County, West Texas, we are developing a contiguous 3,260 acre block with our joint venture partner, Apache Corporation.

In this block

the Company has leasehold acres with interest between 14% and 56%, depending on the particular lease and depth being developed.

In 2018, in this block, eight wells drilled horizontally in the Wolfcamp B, were participated in for 49%

interest and brought on production in February, 2019.

This is believed to be full development of the Wolfcamp B reservoir for this lease block.

Future development is expected in the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs

for this block, following

the 2019 successful development of these reservoirs on our offset 1,280 acre lease block of the Kashmir Tract.

Given the favorable results achieved by the initial three wells on the 1,280 block

it is expected that as many as 54 additional horizontals will be developed on this 3,260 acre block in the near future.

The cost of development would be approximately $370.6 million with the Companys share being approximately

$170.8 million.

In addition to the 54 wells likely to be drilled for these three reservoirs, there is a fourth target reservoir, the Middle Spraberry, that is also prospective for future development.

The potential of the Middle Spraberry on the

3,260 acre block is for 18 horizontal wells to be drilled and completed at a gross cost of approximately $126.3 million with the Companys share being approximately $61.8 million.

The actual number of wells that are eventually drilled

as well as the cost and the timing of drilling will vary based upon many factors, including commodity market conditions.

In addition to

the 3,260 acre block being developed, as described above, the Company is also developing an offsetting 1,280 acre block in Upton County, Texas, with Apache Corporation as operator.

In the second quarter of 2019 three horizontal wells were completed

and brought on production from reservoirs above the Middle Wolfcamp:

In this block the Company has 2,600 leasehold acres with interest between 14% and 56% depending on the particular lease and depth being developed.

In 2018, eight successful wells were drilled horizontally in the Wolfcamp “B” of this block with the Company participating for 49% interest.

This is believed to be full development of the Wolfcamp “B” reservoir.

Together with Apache, we are planning development of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs of this block.

These shallower reservoirs have been proven-up

on our offset 1,300 acre Kashmir tract.

It is expected that as many as 54 additional horizontals will be developed on this 3,260 acres in the near future.

This development is estimated to cost approximately $370.6 million, with the Company’s share being approximately $170.8 million.

In addition to the 54 prospective wells to be drilled for these three reservoirs, a fourth target reservoir, the Middle Spraberry, is also prospective for future development.

The potential of the Middle Spraberry on the 3,260 acre block is for 18 horizontal wells to be drilled and completed at a gross cost of approximately $126.3 million with the Company’s share being approximately $61.8 million.

The actual number of wells that are eventually drilled as well as the cost and the timing of drilling will vary based upon many factors, including commodity market conditions.

In addition to the 3,260 acre block being developed, as described above, the Company is also developing an offsetting 1,300 acre block in Upton County, Texas, with Apache Corporation as operator.

In the second quarter of 2019 three horizontal wells were completed and brought on production from reservoirs above the Middle Wolfcamp:

one in the Wolfcamp “A”, one in the Jo Mill, and one in the Lower Spraberry, confirming the economic viability of these reservoirs on our acreage.

Prime holds 47.5%

working interest in these reservoirs.

As a result of the success of the initial three wells, nine new horizontals were spud in the first quarter of 2020 with six being fully drilled by May, 2020.

The three remaining wells were drilled in the first

quarter of 2021.

All nine of these wells are slated for completion and to be on production by the end of the second quarter of 2021.

Our average 47.5% share of the cost of these nine horizontal wells will be approximately $26.7 million in

In addition to the nine new development locations in the Wolfcamp A, Jo Mill and Lower Sprayberry, four locations in the Middle Spraberry will be considered for future development at an estimated gross cost

of approximately $30.2 million with the Companys share being approximately $14.2 million.

Also in the Permian Basin of

West Texas, we are developing a 965 acre block with Connoco Phillips in Martin County, Texas.

Prime holds 47.5% working interest in these reservoirs.

As a result of the success of the initial three wells, nine new horizontals were completed in the third quarter of 2021.

Our average 47.5% share of the cost of these nine horizontal wells was approximately $26.7 million in total.

In addition to the Wolfcamp “A”, Jo Mill and Lower Spraberry that are now fully developed on the tract, four locations in the Middle Spraberry will be considered for future development at an estimated gross cost of approximately $30.2 million with the Company’s share being approximately $14.2 million.

Also in the Permian Basin of West Texas, we are developing a 965 acre block with ConocoPhillips in Martin County, Texas.

In 2016 and 2017, four horizontal wells were drilled and completed and put on production.

The Company owns 35% to 38% interest in this joint venture

acreage where Connoco Phillips is the operator.

No near-term additional drilling plans have been received from Connoco Phillips, however, offset operators have been actively drilling and their results are encouraging for the future development of

multiple landing zones within this acreage block.

In 2020, the Company also added reserves through a 1% Overriding Royalty Interest

(ORRI) in one horizontal well and 0.56% ORRI in 10 additional horizontal wells in Midland County, Texas.

In Central Reagan County, of

West Texas, during 2020, the Company sold deep rights covering approximately 1,950 acres for net proceeds of $10.8 million.

December 31, 2020, we had net capitalized costs related to proved oil and gas properties of $185,098 million.

Total expenditures for the acquisition, exploration and development of our properties during 2020 were $8.57 million as we

continue development under the programs discussed above.

The Company owns 35% to 38% interest in this joint venture acreage and we have received drilling plans from ConocoPhilips for the drilling of four wells in the third quarter of 2022 that are likely to be 2.5-mile

The Company’s investment in these wells is expected to be $15 million.

In first quarter of 2022, the Company is participating for 10.3% interest with SEM Operating Company in the drilling of four 1.5 mile-long horizontal wells in Irion County, Texas.

We have also received proposals from BTA Oil Producers for the drilling of nine 2.5 mile-long horizontals this year in Reagan County, Texas where the Company intends to participate for its 50% interest in six of the wells and 31% interest in three wells.

Our expected investment in the drilling and completion of these wells is $40.5 million.

In Oklahoma, we are focused on development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 6,200 net leasehold acres in the Scoop/Stack Play.

In 2019, we participated for an average of 4.6% interest with Newfield Exploration in twelve successful wells in Canadian County on our Slash and Wallace tracts.

In 2021, we participated for 11.25% interest with Ovintiv Mid-Continent

in four wells on our Peters tract, in Canadian County.

Three of these wells were successfully completed in December 2021 and online in January 2022, while one well had completion issues and has been temporarily abandoned.

At today’s product prices, payout of the Company’s $2.2 million investment in these four wells is expected to be in approximately six months.

In the first quarter of 2022 the Company received and approved proposals from Ovintiv for four horizontal wells on our Bohlman tract, in the same area as the Peters tract.

The first of these wells is slated to spud April 3, 2022.

The Company will participate with 9.38% interest for approximately $1.8 million through completion which is expected in June.

We believe our 6,200 net leasehold acres has the resource potential to support the drilling of as many as 54 new horizontal wells based on an estimate of four 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.

Significant Activity

As of December 31, 2021, we had net capitalized costs related to proved oil and gas properties of $179.7 million.

Total expenditures for the acquisition, exploration, and development of our properties during 2021 were $18.7 million as we continue development under the programs discussed above.

Proved reserves as of December 31, 2021, were 12.5 MMBOE which consisted of 100% proved developed reserves.

In 2020, the Company acquired approximately 232 net acres in Reagan County, Texas for $343,900 and between 15 and 16.66% working interest in

53 oil and gas wells and 16.66% working interest in one salt water disposal well.

We also acquired net acreage in Upton County located where the Company currently has leasehold acreage and where future horizontal drilling will likely occur.

addition, the Company acquired 9.36 acres in Upton County, Texas for $5,100, where the Company has leasehold acreage with expected future horizontal development.

We believe that our diversified portfolio approach to our drilling activities produces more consistent and predictable economic results than

would otherwise be experienced with a less diversified or higher risk drilling program profile.

DoublePoint Energy now in the process of being acquired by Pioneer Natural Resources, entered into a joint development agreement for the horizontal

development of lands located in Reagan County, Texas in February of 2021 with PrimeEnergy .

The agreement covers approximately 3,680 gross acres of blocked up leasehold to allow for 1.5 and 2 mile horizontal laterals.

We believe this agreement

represents significant future value for PrimeEnergy.

We attempt to assume the position of operator in all acquisitions of producing

During 2021, we participated in the drilling of seven gross horizontal wells and the completion of 12 horizontal wells.

Three of these were completed in September along with six other horizontal wells drilled in 2020 on the same lease in Upton County, Texas.

All nine were put online and began production in late September and early October 2021.

Four of the horizontals drilled in 2021 are located in Canadian County, Oklahoma;

of these, three were completed in December 2021 and brought online in the first week of January 2022, while a fourth had mechanical issues and has been temporarily abandoned.

The Company has 47.5% interest in the nine horizontals located in Upton County, Texas, and 11.25% interest in the four horizontals located in Canadian County, Oklahoma.

In 2021, the Company sold 116 net acres in Martin County Texas, receiving gross proceeds of approximately $1.45 million, while in this same year acquiring 5.9 net acres in Upton County, Texas for $29,500 in an area where the Company currently has leasehold acreage and potential future horizontal drilling.

In the first quarter of 2022, the Company has sold 1809 net leasehold acres in Reagan and Midland Counties, Texas through two separate transactions receiving gross proceeds of $14.1 million.

With the culmination of these sales the Company has reduced its bank debt to $9 million as of March 31, 2022, has the right to borrow up to $50 million under its current revolving line of credit.

We believe that our diversified portfolio approach to our drilling activities produces more consistent and predictable economic results than would otherwise be experienced with a less diversified or higher risk drilling program profile.

We attempt to assume the position of operator in all acquisitions of producing properties.

We will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests and are actively pursuing the acquisition of producing properties.

In order 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 increase our net

worth and increase our oil and gas reserve base.

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 increase our net worth and increase our oil and gas reserve base.

We presently own producing and non-producing

properties located primarily in Texas, and Oklahoma, and we own a substantial amount of well servicing equipment.

We do not own any refinery or marketing facilities, and do not currently own or lease any

bulk storage facilities or pipelines other than adjacent to and used in connection with producing wells and the interests in certain gas gathering systems.

We do not own any refinery or marketing facilities;

and do not currently own or lease any bulk storage facilities or pipelines other than adjacent to and used in connection with producing wells and the interests in certain gas gathering systems.

All of our oil and gas properties and interests are located in the United States.

In the past, the supply of gas has exceeded demand on a cyclical basis, and we are subject to a combination of

shut-in and/or reduced takes of gas production during summer months.

Prolonged shut-ins could result in reduced field operating income from properties in which we act as

Exploration for oil and gas requires substantial expenditures particularly in exploratory drilling in undeveloped areas, or

wildcat drilling. As is customary in the oil and gas industry, substantially all of our exploration and development activities are conducted through joint drilling and operating agreements with others engaged in the oil and gas business.

Summaries of our oil and gas drilling activities, oil and gas production, and undeveloped leasehold, mineral, and royalty interests are

set forth under Item 2., Properties, below.

In the past, the supply of gas has exceeded demand on a cyclical basis, and we are subject to a combination of shut-in

and/or reduced takes of gas production during summer months.

Prolonged shut-ins

could result in reduced field operating income from properties in which we act as operator.

Exploration for oil and gas requires substantial expenditures, particularly in exploratory drilling in undeveloped areas, or “wildcat drilling.” As is customary in the oil and gas industry, substantially all of our exploration and development activities are conducted through joint drilling and operating agreements with others engaged in the oil and gas business.

Summaries of our oil and gas drilling activities, oil and gas production, and undeveloped leasehold, mineral, and royalty interests are set forth under Item 2., “Properties”, below.

Summaries of our oil and gas reserves, future net revenue and present value of future net revenue are also set forth under Item 2., “Properties—Reserves”, below.

Well Operations

Our operations

are conducted through our principal offices in Houston, Texas, and district offices in Houston and Midland, Texas, and Oklahoma City, Oklahoma.

We currently operate 760 active wells, including producing, saltwater disposal, injection, and supply

Our operations are conducted through our principal offices in Houston, Texas, and district offices in Houston and Midland, Texas, and Oklahoma City, Oklahoma.

We currently operate 710 wells, including producing, saltwater disposal, injection, and supply wells:

144 through the Houston office, 327 through the Midland office, and 239 through the Oklahoma City office.

Substantially all of the wells we operate are wells in which we have an interest.

We operate wells pursuant to operating agreements that govern the relationship between us, as operator, and the other owners of working

interests in the properties, including the Partnerships, Trusts and joint venture participants.

For each operated well, we receive monthly fees that are competitive in the areas of operations and we also are reimbursed for expenses incurred in

connection with well operations.

We operate wells pursuant to operating agreements that govern the relationship between us, as operator, and the other owners of working interests in the properties, including the Partnerships, Trusts and joint venture participants.

For each operated well, we receive monthly fees that are competitive in the areas of operations and we also are reimbursed for expenses incurred in connection with well operations.

The Partnerships, Trusts and Joint Ventures

Since 1975, PEMC has acted as managing general partner of various partnerships, trusts and joint ventures.

PEMC, as managing general partner of the Partnerships and managing trustee of the Trusts, is responsible for all Partnership and Trust

activities, the drilling of development wells and the production and sale of oil and gas from productive wells.

PEMC also provides administration, accounting and tax preparation for the Partnerships and Trusts from our offices in Houston, Texas.

PEMC is liable for all debts and liabilities of the Partnerships and Trusts, to the extent that the assets of a given limited partnership or trust are not sufficient to satisfy its obligations.

We stopped sponsoring partnerships and trusts in 1992.

As we entered 2021, we only have one partnership and one trust remaining.

All other partnerships and the other trusts have been liquidated.

The aggregate number of limited partners in the Partnerships and beneficial owners of the Trusts now

administered by PEMC is approximately 69.

Since 1975, PEMC acted as managing general partner of various partnerships, trusts and joint ventures.

As we entered into 2021, we had one partnership and one trust remaining.

During 2021 the remaining partnership and trust were liquidated.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations.

Failure to comply with applicable laws and

regulations can result in substantial penalties.

Failure to comply with applicable laws and regulations can result in substantial penalties.

The regulatory burden on the industry increases the cost of doing business and affects profitability.

Although we believe we are in substantial compliance with all applicable laws and regulations,

such laws and regulations are frequently amended or reinterpreted.

Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted.

Therefore, we are unable to predict the future costs or impact of compliance.

Additional proposals and proceedings that affect the oil and natural gas industry are regularly

considered by the United States Congress (Congress), state governments, the Federal Energy Regulatory Commission (the FERC) and other federal and state regulatory agencies and federal, state and local courts.

predict when or whether any such proposals may become effective.

Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by the United States Congress (“Congress”), state governments, the Federal Energy Regulatory Commission (the “FERC”) and other federal and state regulatory agencies and federal, state and local courts.

We cannot predict when or whether any such proposals may become effective.

We do not believe that such action or proposal would have a material disproportionate effect on us as compared to similarly situated competitors.

Regulation Affecting Production

As described above, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws

and regulations.

In addition, all of the jurisdictions in which we own or operate producing oil and natural gas

properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements

to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process and the

abandonment of wells.

As described above, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations.

In addition, all of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling

and completion process and the abandonment of wells.

Our operations are also subject to various conservation laws and regulations.

These include the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area and the

unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields

and individual wells.

These include the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

These laws and regulations may limit the number of oil and natural gas wells we can drill.

Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and

NGLs within its jurisdiction.

Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future.

The effect of such future regulations may be to limit the

amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or limit the number of locations we can drill.

The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial

The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or limit the number of locations we can drill.

The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties.

Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

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Sales prices for oil, natural gas and NGLs are not currently regulated and therefore are dictated by the prevailing market prices.

prices of these energy commodities are currently unregulated, Congress historically has been active in their regulation.

We cannot predict whether new legislation to regulate oil and natural gas, or the prices charged for these commodities, might be

proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on our operations.

Sales of oil and natural gas may be subject to certain state and federal

reporting requirements.

The price and terms of service of transportation of commodities, including access to pipeline transportation

capacity, are subject to extensive federal and state regulation.

Although prices of these energy commodities are currently unregulated, Congress historically has been active in their regulation.

We cannot predict whether new legislation to regulate oil and natural gas, or the prices charged for these commodities, might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on our operations.

Sales of oil and natural gas may be subject to certain state and federal reporting requirements.

The price and terms of service of transportation of commodities, including access to pipeline transportation capacity, are subject to extensive federal and state regulation.

Such regulation may affect the marketing of oil and natural gas produced, as well as the revenues received for sales of such production.

Gathering systems may be subject to state

ratable take statutes and common purchaser statutes.

Gathering systems may be subject to state ratable take statutes and common purchaser statutes.

Ratable take statutes generally require gatherers to take, without undue discrimination, oil and natural gas production that may be tendered to the gatherer for handling.

Similarly, common

purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer.

These statutes are designed to prohibit discrimination in favor of one producer over another

producer or one source of supply over another source of supply.

Similarly, common purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer.

These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply.

These statutes may affect whether and to what extent gathering capacity is available for oil and natural gas production, if any, of the drilling program and the cost of such capacity.

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The FERC regulates interstate natural gas pipeline transportation rates and service conditions.

The FERC regularly proposes and implements new

rules and regulations affecting interstate transportation.

The FERC regularly proposes and implements new rules and regulations affecting interstate transportation.

The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and to promote market transparency.

We do not believe

that such FERC action would have a material disproportionate effect on our drilling program as compared to other similarly situated natural gas producers.

Gathering services, which occur upstream of FERC jurisdictional transmission services, and which are performed onshore and in state-controlled

waters are regulated by state governments.

Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission

function, the FERCs determinations as to the classification of facilities is conducted on a case-by-case basis.

State regulation of natural gas gathering

facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements.

Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive

greater regulatory scrutiny in the future.

In addition to the regulation of natural gas pipeline transportation, the FERC has

jurisdiction over the purchase or sale of gas or the purchase or sale of transportation services subject to the FERCs jurisdiction pursuant to the Energy Policy Act of 2005.

Under this law, it is unlawful for any entity, including

a producer such as us, that is otherwise not subject to the FERCs jurisdiction under the Natural Gas Act of 1938 to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas, or the purchase or sale

of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC.

The FERCs rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the

jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud, to make any untrue statement of

material fact or omit to make any such statement necessary to make the statements made not misleading, or to engage in any act or practice that operates as a fraud or deceit upon any person.

The Energy Policy Act of 2005 also gives the FERC

authority to impose civil penalties for

violations of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 up to $1,291,894 per day per violation (adjusted annually based on inflation) and disgorge profits associated with

any violation.

The anti-manipulation rule applies to activities of otherwise non-jurisdictional entities to the extent the activities are conducted in connection with gas sales, purchases or

transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order 704 (defined below).

December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (Order 704).

Under Order 704, any market participant that engages in wholesale sales

or purchases of gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, must annually report such sales and purchases to the FERC on Form No.

We do not believe that such FERC action would have a material disproportionate effect on our drilling program as compared to other similarly situated natural gas producers.

Gathering services, which occur upstream of FERC jurisdictional transmission services, and which are performed onshore and in state-controlled waters are regulated by state governments.

Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional

gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is conducted on a case-by-case

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements.

Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

In addition to the regulation of natural gas pipeline transportation, the FERC has jurisdiction over the purchase or sale of gas or the purchase or sale of transportation services subject to the FERC’s jurisdiction pursuant to the Energy Policy Act of 2005.

Under this law, it is unlawful for “any entity,” including a producer such as us, that is otherwise not subject to the FERC’s jurisdiction under the Natural Gas Act of 1938 to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas, or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC.

The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud, to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading, or to engage in any act or practice that operates as a fraud or deceit upon any person.

The Energy Policy Act of 2005 also gives the FERC authority to impose civil penalties for violations of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 up to $1,291,894 per day per violation (adjusted annually based on inflation) and disgorge profits associated with any violation.

The anti-manipulation rule applies to activities of otherwise non-jurisdictional

entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order 704 (defined below).

In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”).

Under Order 704, any market participant that engages in wholesale sales or purchases of gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, must annually report such sales and purchases to the FERC on Form No.

552 on May 1 of each year.

552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize or contribute to the formation of price indices.

It is the responsibility of the reporting entity to

determine which individual transactions should be reported based on the guidance of Order 704.

Order 704 is intended to increase the transparency of the wholesale gas markets and to assist the FERC in monitoring those markets and in detecting market

manipulation.

The FERC also regulates rates and service conditions for the interstate transportation of liquids, including oil and NGLs,

under the Interstate Commerce Act (the ICA).

It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704.

Order 704 is intended to increase the transparency of the wholesale gas markets and to assist the FERC in monitoring those markets and in detecting market manipulation.

The FERC also regulates rates and service conditions for the interstate transportation of liquids, including oil and NGLs, under the Interstate Commerce Act (the “ICA”).

Prices received from the sale of liquids may be affected by the cost of transporting those products to market.

The ICA requires that pipelines maintain a tariff on file with the FERC.

tariff sets forth the established rates as well as the rules and regulations governing the service.

The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be just and

reasonable. Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential.

Shippers have the power to challenge new and existing rates and terms and conditions of service before

Rates of interstate liquids pipelines are currently regulated by the FERC primarily through an annual indexing methodology,

under which pipelines increase or decrease their rates in accordance with an index adjustment specified by the FERC.

For the five-year period beginning on July 1, 2016, the FERC established an annual index adjustment equal to the change in the

producer price index for finished goods plus 1.23%.

The tariff sets forth the established rates as well as the rules and regulations governing the service.

The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential.

Shippers have the power to challenge new and existing rates and terms and conditions of service before the FERC.

Rates of interstate liquids pipelines are currently regulated by the FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by the FERC.

For the five-year period beginning on July 1, 2016, the FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%.

This adjustment is subject to review every five years.

Under the FERCs regulations, a liquids pipeline can request the authority to charge market-based rates for transportation service if it

satisfies certain criteria, and also can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a

cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates

resulting from application of the indexing methodology.

Under the FERC’s regulations, a liquids pipeline can request the authority to charge market-based rates for transportation service if it satisfies certain criteria, and also can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service

approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology.

Increases in liquids transportation rates may result in lower revenue and cash flows.

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable

manner in the event there are nominations in excess of capacity.

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity.

Therefore, requests for service by new shippers or increased volume by existing shippers may reduce the capacity available to us.

Any prolonged interruption in the operation or

curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows.

However, we believe that access to

liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we

rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows.

However, we believe that access to liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions.

The basis for intrastate liquids

pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state.

We believe that the regulation of liquids pipeline transportation rates will not affect our operations

in any way that is materially different from the effects on our similarly situated competitors.

In addition to the FERCs

regulations, we are required to observe anti-market manipulation laws with regard to our physical sales of energy commodities.

In November 2009, the Federal Trade Commission (the FTC) issued regulations pursuant to the Energy

Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry.

The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state.

We believe that the regulation of liquids pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly situated competitors.

In addition to the FERC’s regulations, we are required to observe anti-market manipulation laws with regard to our physical sales of energy commodities.

In November 2009, the Federal Trade Commission (the “FTC”) issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry.

Violators of the regulations face civil penalties of up to $1,231,690 per violation per day (adjusted annually based on inflation).

2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (the CFTC) to prohibit market manipulation in the markets regulated by the CFTC.

This authority, with

respect to crude oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to crude oil purchases and sales.

In July 2011, the CFTC issued final rules to implement its new anti-manipulation

In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (the “CFTC”) to prohibit market manipulation in the markets regulated by the CFTC.

This authority, with respect to crude oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to crude oil purchases and sales.

In July 2011, the CFTC issued final rules to implement its new anti-manipulation authority.

The rules subject violators to a civil penalty of up to the greater of $1,212,866 (adjusted annually based on inflation) or triple the monetary gain to the person for each violation.

Regulation of Environmental and Occupational Safety and Health Matters

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as

the discharge of materials into the environment and occupational health and safety.

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment and occupational health and safety.

These laws and regulations may, among other things:

(i) require the acquisition of permits to conduct exploration, drilling and production operations;

(ii) restrict

the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production

(ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities;

(iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

(iv) require remedial measures to mitigate pollution from former and ongoing operations, such as

requirements to close pits and plug abandoned wells;

(iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells;

and (v) impose substantial liabilities for pollution resulting from drilling and production operations.

Any failure to comply with these laws and regulations may result in the assessment of

administrative, civil and criminal penalties, the imposition of corrective or remedial obligations and the issuance of orders enjoining performance of some or all of our operations.

Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations and the issuance of orders enjoining performance of some or all of our operations.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible.

regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.

Additionally, Congress and federal and state agencies frequently revise environmental laws and

regulations and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The clear trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment

and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transportation, disposal, or

remediation requirements could have a material adverse effect on our financial position and results of operations.

The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.

Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The clear trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus any changes in environmental laws and regulations or re-interpretation

of enforcement policies that result in more stringent and costly waste handling, storage, transportation, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations.

We may be unable to pass on such increased compliance costs to our purchasers.

Moreover, accidental releases or spills may occur in

the course of our operations and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

compliance with existing environmental laws and regulations has not had a material adverse effect on our operations to date, we can provide no assurance that this will continue in the future.

The following is a summary of the more significant existing and proposed environmental, occupational health and safety laws and regulations to

which our business operations are or may be subject to and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Moreover, accidental releases or spills may occur in the course of our operations and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

While compliance with existing environmental laws and regulations has not had a material adverse effect on our operations to date, we can provide no assurance that this will continue in the future.

The following is a summary of the more significant existing and proposed environmental, occupational health and safety laws and regulations to which our business operations are or may be subject to and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

The Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act (RCRA), and comparable state statutes, regulate the generation, transportation,

treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes.

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous

Pursuant to rules issued by the U.S.

Environmental Protection Agency (the EPA), individual state governments

administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements.

Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of

crude oil or natural gas are currently regulated under RCRAs non-hazardous waste provisions.

However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future.

A change in the classification of exploration and production wastes has the potential to significantly increase our waste disposal costs to

manage, which in turn will result in increased operating costs and could adversely impact our results of operations and financial position.

Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint

wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

Comprehensive

Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act

(CERCLA), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the

Environmental Protection Agency (the “EPA”), individual state governments administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements.

Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous

waste provisions.

However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous

could be classified as hazardous wastes in the future.

A change in the classification of exploration and production wastes has the potential to significantly increase our waste disposal costs to manage, which in turn will result in increased operating costs and could adversely impact our results of operations and financial position.

Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.

These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site.

Under CERCLA, such persons may

be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.

In addition, it is not

uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.

In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We generate materials in the course of our operations that may be regulated as hazardous substances.

Despite the petroleum

exclusion of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and

severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

In addition, we currently own, lease, or operate numerous properties that have been

used for oil and natural gas exploration, production and processing for many years.

Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or

hydrocarbons may have been released on,

under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been

taken for disposal.

Despite the “petroleum exclusion” of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

In addition, we currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years.

Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site

locations, where such substances have been taken for disposal.

In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control.

These properties

and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state and local laws.

Under such laws, we could be required to undertake investigatory, response, or corrective measures, which could include

soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup of contaminated property, or remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.

These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state and local laws.

Under such laws, we could be required to undertake investigatory, response, or corrective measures, which could include soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup of contaminated property, or remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.

Water Discharges

Water Pollution Control Act, or the Clean Water Act (the CWA), and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into

waters of the United States.

The Federal Water Pollution Control Act, or the Clean Water Act (the “CWA”), and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States.

The discharge of pollutants into regulated waters, including wetland areas, is prohibited, except in accordance with the terms of a permit issued by the EPA, the U.S.

Army Corps of Engineers (the USACE) or an

analogous state agency.

In September 2015, the EPA and the USACE issued a final rule redefining the scope of the EPAs and the USACEs jurisdiction under the CWA with respect to certain types of waterbodies and classifying these

waterbodies as regulated wetlands (the WOTUS rule).

Army Corps of Engineers (the “USACE”) or an analogous state agency.

In September 2015, the EPA and the USACE issued a final rule redefining the scope of the EPA’s and the USACE’s jurisdiction under the CWA with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands (the “WOTUS” rule).

Several legal challenges to the rule followed, along with attempts to stay implementation of the WOTUS rule following the change in U.S.

presidential administrations.

Currently, the

WOTUS rule is active in 22 states and enjoined in 28 states.

However, in December 2018, the EPA and the USACE proposed changes to regulations under the CWA that would provide discrete categories of jurisdictional waters and tests for determining

whether a particular waterbody meets any of those classifications.

Currently, the WOTUS rule is active in 22 states and enjoined in 28 states.

However, in December 2018, the EPA and the USACE proposed changes to regulations under the CWA that would provide discrete categories of jurisdictional waters and tests for determining whether a particular waterbody meets any of those classifications.

Several groups have already announced their intent to challenge the proposed WOTUS replacement rule.

Therefore, the scope of jurisdiction under the CWA is uncertain at this time.

the extent the original WOTUS rule or any replacement rule expands the scope of the CWAs jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and

To the extent the original WOTUS rule or any replacement rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance

with discharge permits or other requirements of the CWA and analogous state laws and regulations.

We do not expect the costs to comply with the requirements of the CWA to have a material adverse effect on our operations.

The Oil Pollution Act of 1990 amends the CWA and establishes strict liability for owners and operators of facilities that cause a release of

oil into waters of the United States.

The Oil Pollution Act of 1990 amends the CWA and establishes strict liability for owners and operators of facilities that cause a release of oil into waters of the United States.

In addition, this law requires owners and operators of facilities that store oil above specified threshold amounts to develop and implement spill prevention, control and countermeasures plans.

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In the course of our operations, we produce water in addition to oil and natural gas.

Water that is not recycled or otherwise disposed of on

the lease may be sent to saltwater disposal wells for injection into subsurface formations.

Underground injection operations are regulated under the federal Safe Drinking Water Act and permitting and enforcement authority may be delegated to state

Water that is not recycled or otherwise disposed of on the lease may be sent to saltwater disposal wells for injection into subsurface formations.

Underground injection operations are regulated under the federal Safe Drinking Water Act and permitting and enforcement authority may be delegated to state governments.

In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well.

The RRC requires operators to obtain a permit from the agency for the operation of saltwater disposal wells and

establishes minimum standards for injection well operations.

In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related waste waters, federal and

some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection

The RRC requires operators to obtain a permit from the agency for the operation of saltwater disposal wells and establishes minimum standards for injection well operations.

In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related

waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection wells.

In response to concerns related to induced seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety.

For example, the RRC has adopted rules for injection wells to

address these seismic activity concerns in Texas.

Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for

certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.

More stringent regulation of injection wells could lead to reduced construction

or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations.

Increased costs associated with the transportation and disposal of produced water, including the cost of

complying with regulations concerning produced water disposal, may reduce our profitability.

The costs associated with the disposal of proposed water are commonly incurred by all oil and natural gas producers, however, and we do not believe that

these costs will have a material adverse effect on our operations.

For example, the RRC has adopted rules for injection wells to address these seismic activity concerns in Texas.

Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.

More stringent regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations.

Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability.

The costs associated with the disposal of proposed water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations.

Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and

compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements.

These laws and regulations may require us to obtain

pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply

with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants.

Over the next several years, we may be required to incur certain

capital expenditures for air pollution control equipment or other air emissions related issues.

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements.

These laws and regulations may require us to obtain pre-approval

for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants.

Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues.

For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard for ozone from 75 to 70 parts per billion.

The EPA approved final

attainment/nonattainment designations with the new ozone standards in July 2018 and currently all of the areas in which we operate are in attainment with such standards.

However, state implementation of these revised air quality standards or a

change in the attainment status of the areas in which we operate could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs

of which could be significant.

Separately, in June 2016, the EPA finalized a rule regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes

applicable to the oil and natural gas industry.

This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational

delays or require us to install costly pollution control equipment.

The EPA has also adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells

for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as green completions. These regulations also establish specific new requirements regarding emissions from

production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels.

The EPA expanded on its emission standards for volatile organic compounds in June 2016 with the issuance of first-time standards, known as

Subpart OOOOa, to address emissions of methane from equipment and processes across the oil and natural gas source category, including hydraulically fractured oil and natural gas well completions.

Following the change in presidential

administration, there have been attempts to modify these regulations, and litigation concerning the regulations is ongoing.

As a result of these developments, substantial uncertainty exists with respect to implementation of the EPAs 2016

methane rule.

However, given the long-term trend toward increasing regulation, future federal methane regulation of the oil and gas industry remains a possibility, and several states have separately imposed their own regulations on methane emissions

from oil and gas production activities.

These and other air pollution control and permitting requirements have the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs

could be significant.

The EPA approved final attainment/nonattainment designations with the new ozone standards in July 2018 and currently all of the areas in which we operate are in attainment with such standards.

However, state implementation of these revised air quality standards or a change in the attainment status of the areas in which we operate could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant.

Separately, in June 2016, the EPA finalized a rule regarding criteria for aggregating multiple small surface sites into a single source for air-quality

permitting purposes applicable to the oil and natural gas industry.

This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment.

The EPA has also adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels.

The EPA expanded on its emission standards for volatile organic compounds in June 2016 with the issuance of first-time standards, known as Subpart OOOOa, to address emissions of methane from equipment and processes across the oil and natural gas source category, including hydraulically fractured oil and natural gas well completions.

Following the change in presidential administration, there have been attempts to modify these regulations, and litigation concerning the regulations is ongoing.

As a result of these developments, substantial uncertainty exists with respect to implementation of the EPA’s 2016 methane rule.

We do not believe that compliance with such requirements, however, will have a material adverse effect on our operations.

Regulation of Greenhouse Gas Emissions

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (GHGs) endanger public health and the

environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (PSD), construction and Title V operating permit reviews for certain

large stationary sources.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) endanger public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for certain large stationary sources.

Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards for these emissions.

EPA rulemakings related to GHG emissions could

adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

In addition, the EPA has adopted rules requiring the annual reporting of GHG emissions from certain petroleum and natural gas system

sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our operations.

Also, as noted above, the EPA has promulgated a New Source Performance Standard related to methane emissions from the

oil and natural gas source category.

While Congress has considered legislation related to the reduction of GHG emissions in the past, no

significant legislation to reduce GHG emissions has been adopted at the federal level.

In the absence of Congressional action, a number of state and regional GHG restrictions have emerged.

At the international level, the United States joined the

international community at the 21 st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France.

EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

In addition, the EPA has adopted rules requiring the annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our operations.

Also, as noted above, the EPA has promulgated a New Source Performance Standard related to methane emissions from the oil and natural gas source category.

While Congress has considered legislation related to the reduction of GHG emissions in the past, no significant legislation to reduce GHG emissions has been adopted at the federal level.

In the absence of

Congressional action, a number of state and regional GHG restrictions have emerged.

At the international level, the United States joined the international community at the 21 st

Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France.

The Paris Agreement entered into force in November 2016.

Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges from participating nations to voluntarily limit or reduce future emissions.

In June 2017, President Trump stated

that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs.

The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which

would result in an effective exit date of November 2020.

The United States adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are

unclear at this time.

on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.

Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to represent a major share of global energy use through 2040, and other private sector studies

project continued growth in demand for the next two decades.

However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the

energy sector.

Finally, it should also be noted that many scientists have concluded that increasing concentrations of GHGs in the Earths atmosphere may produce climate changes that have significant physical effects, such as increased frequency

and severity of storms, floods, droughts and other climatic events;

In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs.

The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020.

The United States’ adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.

Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.

However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.

Finally, it should also be noted that many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events;

if any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface

rock formations.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.

Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production.

We regularly use hydraulic

fracturing as part of our operations.

Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, resulting in new legislative and regulatory initiatives that

seek to increase the regulatory burden imposed on hydraulic fracturing.

At the federal level, the EPA has asserted federal regulatory

authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities.

Further, the EPA

finalized regulations under the CWA in June 2016 that prohibit wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants.

Also, in December 2016, the EPA released its final

report on the potential impacts of hydraulic fracturing on drinking water resources.

The final report concluded that water cycle activities associated with hydraulic fracturing may impact drinking water resources under certain limited

circumstances.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent

permitting, disclosure and well construction requirements on hydraulic fracturing activities.

For example, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations

do not contaminate nearby water resources.

We regularly use hydraulic fracturing as part of our operations.

At the federal level, the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities.

Further, the EPA finalized regulations under the CWA in June 2016 that prohibit wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants.

Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources.

The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities.

For example, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources.

Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of, or prohibiting, drilling or hydraulic fracturing activities.

We believe that we

follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities.

Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic

fracturing process are adopted in areas where we operate, we may be required to incur significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities and

perhaps even be precluded from drilling wells.

If new federal, state or local laws or regulations that significantly restrict hydraulic

fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform fracturing.

Any such regulations limiting or prohibiting hydraulic fracturing

could reduce oil and natural gas exploration and production activities and, therefore, adversely affect our business.

Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how

hydraulic fracturing wastes are handled or disposed.

We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities.

Nonetheless, if new or more

stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we may be required to incur significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be precluded from drilling wells.

If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform fracturing.

Any such regulations limiting or prohibiting hydraulic fracturing could reduce oil and natural gas exploration and production activities and, therefore, adversely affect our business.

Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.

Endangered Species Act and Migratory Birds

The federal Endangered Species Act (ESA) and (in some cases) comparable state laws were established to protect endangered and

threatened species.

The federal Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species.

Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat.

We may conduct operations on oil and natural gas leases in areas

where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist.

Fish and Wildlife

Service (the FWS) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of a threatened or endangered species.

A critical habitat or suitable habitat designation could result in further

material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development.

Moreover, as a result of a 2011 settlement agreement, the FWS was required to make a determination on listing of more

than 250 species as endangered or threatened under the FSA by no later than completion of the agencys 2017 fiscal year.

The FWS missed the deadline but reportedly continues to review new species for protected status under the ESA pursuant to

the settlement agreement.

We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist.

Fish and Wildlife Service (the “FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of a threatened or endangered species.

A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development.

Moreover, as a result of a 2011 settlement agreement, the FWS was required to make a determination on listing of more than 250 species as endangered or threatened under the FSA by no later than completion of the agency’s 2017 fiscal year.

The FWS missed the deadline but reportedly continues to review new species for protected status under the ESA pursuant to the settlement agreement.

Similar protections are offered to migratory birds under the Migratory Bird Treaty Act.

Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes

portions of the Permian Basin, and to reconsider listing the species under the ESA.

The designation as threatened or endangered of previously unprotected species in areas where we operate could cause us to incur increased costs arising from species

protection measures or could result in limitations on our development and production activities that could have a material adverse impact on our ability to develop and produce our reserves.

If we were to have a portion of our leases designated as

critical or suitable habitat, it could adversely impact the value of our leases.

We are subject to the requirements of the Occupational Safety and Health Administration (OSHA) and comparable state statutes whose

purpose is to protect the health and safety of workers.

In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and

comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local

governmental authorities and citizens.

Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA.

The designation as threatened or endangered of previously unprotected species in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our development and production activities that could have a material adverse impact on our ability to develop and produce our reserves.

If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

We are subject to the requirements of the Occupational Safety and Health Administration (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers.

In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know

Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain

drilling, construction, production, operation, or other oil and natural gas activities and to maintain these permits and compliance with their requirements for on-going operations.

These permits are generally

subject to protest, appeal, or litigation, which, in certain cases, can delay or halt projects and cease production or operation of wells, pipelines and other operations.

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities and to maintain these permits and compliance with their requirements for on-going

These permits are generally subject to protest, appeal, or litigation, which, in certain cases, can delay or halt projects and cease production or operation of wells, pipelines and other operations.

Related Insurance

insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities.

However, this insurance is limited to activities at the well site, and there can be no assurance

that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us.

The occurrence of a significant event that is not fully insured or indemnified against could

have a material adverse effect on our financial condition and operations.

Although we have not experienced any material adverse effect

from compliance with environmental requirements, there is no assurance that this will continue.

We did not have any material capital or other non-recurring expenditures in connection with complying with

environmental laws or environmental remediation matters in 2019, nor do we anticipate that such expenditures will be material in 2020.

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities.

However, this insurance is limited to activities at the well site, and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us.

The occurrence of a significant event that is not fully insured or indemnified against could have a material adverse effect on our financial condition and operations.

Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue.

We did not have any material capital or other non-recurring

expenditures in connection with complying with environmental laws or environmental remediation matters in 2021, nor do we anticipate that such expenditures will be material in 2022.

Competition and Markets

business of acquiring producing properties and non-producing leases suitable for exploration and development is highly competitive.

Our competition, in our efforts to acquire both producing and non-producing properties, include oil and gas companies, independent concerns, income programs and individual producers and operators, many of which have financial resources, staffs and facilities substantially

greater than those available to us.

Furthermore, domestic producers of oil and gas must not only compete with each other in marketing their output, but must also compete with producers of imported oil and gas and alternative energy sources such as

coal, nuclear power and hydroelectric power.

The business of acquiring producing properties and non-producing

leases suitable for exploration and development is highly competitive.

Our competition, in our efforts to acquire both producing and non-producing

properties, include oil and gas companies, independent concerns, income programs and individual producers and operators, many of which have financial resources, staffs and facilities substantially greater than those available to us.

Competition among petroleum companies for favorable oil and gas properties and leases can be expected to increase.

The availability of a ready market for any oil and gas produced by us at acceptable prices per unit of production will depend upon numerous

factors beyond our control, including the extent of domestic production and importation of oil and gas, the proximity of our producing properties to gas pipelines and the availability and capacity of such pipelines, the marketing of other

competitive fuels, fluctuation in demand, governmental regulation of production, refining, transportation and sales, general national and worldwide economic conditions, and use and allocation of oil and gas and their substitute fuels.

assurance that we will be able to market all of the oil or gas produced by us or that favorable prices can be obtained for the oil and gas production.

derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs.

The availability of a ready market for any oil and gas produced by us at acceptable prices per unit of production will depend upon numerous factors beyond our control, including the extent of domestic production and importation of oil and gas, the proximity of our producing properties to gas pipelines and the availability and capacity of such pipelines, the marketing of other competitive fuels, fluctuation in demand, governmental regulation of production, refining, transportation and sales, general national and worldwide economic conditions, and use and allocation of oil and gas and their substitute fuels.

There is no assurance that we will be able to market all of the oil or gas produced by us or that favorable prices can be obtained for the oil and gas production.

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.

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.

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consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs.

The price of oil and natural gas has fallen

significantly since the beginning of 2020, due in part to failed Organization of Petroleum Exporting Countries (OPEC) negotiations as well as concerns about the COVID-19 pandemic and its impact on

the worldwide economy and global demand for oil and gas.

The resulting precipitous decline in oil and gas pricing experienced during March 2020, through the date of this report, if prolonged, or a further deterioration of the market price for oil

and natural gas, will negatively impact our cash flows.

We have an active hedging program to mitigate risk regarding our cash flow and to

protect returns from our development activity in the event of decreases in the prices received for our production;

however, hedging arrangements may expose us to risk of financial loss in some circumstances and may limit the benefit we would receive

from increases in the prices for oil, natural gas and NGLs.

We have an active hedging program to mitigate risk regarding our cash flow and to protect returns from our development activity in the event of decreases in the prices received for our production;

however, hedging arrangements may expose us to risk of financial loss in some circumstances and may limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs.

Major Customers

The Company sells its oil and gas production to a number of direct purchasers under direct contracts or through other operators under joint

operating agreements.

The Company sells its oil and gas production to a number of direct purchasers under direct contracts or through other operators under joint operating agreements.

Listed below are the percent of the Company’s total oil and gas sales made which represented more than 10% of the Company’s oil and gas sales in the year 2021.

4 unchanged sentences

Apache Corporation

Targa Pipeline Mid-Continent West Tex, LLC

Although there are no long-term purchasing agreements with these purchasers, we believe that they will

continue to purchase our oil and gas products and, if not, could be readily replaced by other purchasers.

At December 31, 2020, we had 96 full time employees, 26 of whom were employed at our principal offices in Houston, Texas, at the offices

of Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company, and 70 employees who were primarily involved in our district operations in Midland, Texas, Elmore City and Oklahoma City, Oklahoma.

Targa Pipeline Mid-Continent

West Tex, LLC

Although there are no long-term purchasing agreements with these purchasers, we believe that they will continue to purchase our oil and gas products and, if not, could be readily replaced by other purchasers.

At December 31, 2021, we had 113 full time employees, 31 of whom were employed at our principal offices in Houston, Texas, at the offices of Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company, and 82 employees who were primarily involved in our district operations in Midland, Texas, Elmore City and Oklahoma City, Oklahoma.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business