What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2021-04-26 compared with 2020-05-06 · 303 added, 336 removed, 252 unchanged (72% of the section changed)

3 unchanged sentences

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, Oklahoma and West Virginia.

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 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 three oil and gas limited partnerships (the Partnerships), and acts as the managing trustee of two asset and income business trusts (the

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

2 unchanged sentences

reserves primarily through horizontal drilling.

This strategy includes targeting reservoirs with high initial production rates and cash flow as well as other reservoirs with lower initial production rates but that are sustained longer and that

expected to deliver a higher expected return on investment.

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 2020, we will continue our focus on

preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

Our 2020 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.

Under SEC rules governing the scheduling

of development of proved undeveloped (PUD) reserves, our year-end reserve report includes only those 12 PUD locations that at year-end had been drilled but not yet

completed, along with ten new locations originally slated to be drilled in 2020.

Of these ten, the Company is participating for an average 42% in seven wells that have been drilled as of April 15, 2020, and are awaiting completion.

locations drilled but not completed at year-end 2019, the Company has 10% interest in one well and less than one percent interest in each of three wells, and over-riding royalty interest only in eight wells.

Since the start of our West Texas horizontal drilling program in 2015 and through the fourth quarter of 2019 the Company has participated

in 67 horizontal wells in the Permian Basin, 11 of which were brought into production in 2019.

As of year-end, the Company has invested approximately $104 MM.

Of the total 67

horizontal wells in this program, the Company has an average of 28.19% interest in 52 wells, and less than one percent interest in 15 wells.

Of the 11 wells brought on production in 2019,

the Company has 49% interest in eight wells on our CC-33 tract that are one-mile in length, as well as an average 49% interest in two wells, and 5.3% interest in one

well that are each two-miles in length, located on our Kashmir tract.

Our investment in these 11 new horizontal wells was approximately $31.5 million, including production facilities.

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 2,600 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 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.

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.

Apache will likely now set its sights on

development of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs for this block, following the recent successful testing in 2019 of these reservoirs on our offset 1,300 acre lease block.

Given the favorable results achieved by the initial

three wells on this block, it is expected that as many as 54 additional horizontals will be slated for development on this 3,260 acre block in the near future.

The cost of such development would be approximately $370.6 million with the

Companys share being approximately $170.8 million.

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.

potential of the Middle Spraberry on the 3,280 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.

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:

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:

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 between 5% and 48% working interest in

various depths of this acreage, and of the $26.7 million development cost for these three wells, our share was approximately $9.2 million.

As a result of the success of these initial three wells, nine new horizontals have been spud in the

first quarter of 2020 and six of these were finished being drilled in April.

These six are expected to be on production in the fourth quarter of 2020.

Our average 47.76% share of the cost of these six horizontal wells will be approximately

Drilling of the remaining three wells is expected to be delayed until 2021.

In addition to the nine new development locations in the Wolfcamp A, Jo Mill and Lower Sprayberry of our

1,300-acre block with Apache Corporation, there are four locations in the Middle Spraberry that are likely to be considered for future development at an estimated gross cost of approximately

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

Along with the six horizontal wells drilled in early 2020 in Upton County, the Company participated for 7.7% interest in the horizontal drilling of a well

operated by Pioneer Natural Resources that is expected to be completed in the fourth quarter of 2020.

Our total net expenditure for this well is estimated to be $580,400.

Also in the Permian Basin of West Texas, we are developing a 965-acre block with Concho Resources 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 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.

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 Concho Resources is the operator.

No near-term additional

drilling plans have been received from Concho Resources, however, offset operators have been actively drilling and their results are encouraging for the future development of multiple landing zones within this acreage block.

Since the start of our Oklahoma Scoop-Stack horizontal development program, which began in 2013, the Company has participated in 41 horizontal

wells for approximately $23.9 million through the fourth quarter of 2019 with an average of approximately 7% interest.

During this same period the Company chose to retain an overriding royalty interest in an additional 61 horizontal wells.

2019, the Company participated for an average

4.46% interest in 21 horizontal wells in Canadian, Grady, and Kingfisher counties for a net cost of approximately $7 million.

Seventeen of these were drilled and completed in 2019, and of

these twelve were operated by Encana/Newfield.

Four of the 21 wells were drilled but not yet been completed at year-end.

Also during 2019, the Company retained an overriding royalty interest in nine wells that

were completed by year-end, as well as in nine additional wells that are expected to be completed in 2020.

Also in 2020, we anticipate the drilling of an additional six wells by Encana/Newfield on our Peters

tract in Canadian County, Oklahoma in which we will have the opportunity to participate for approximately 11.25%, with our share of drilling and completion cost expected to be approximately $4.7 million.

Our horizontal activity in Oklahoma is focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have

approximately 3,460 net acres.

We believe this acreage has significant additional resource potential that could support the drilling of as many as 52 new horizontals based on an estimate of six wells per section:

three in the Mississippian and three

in the Woodford Shale.

Should we choose to participate in future development, our share of the capital expenditures would be approximately $40 million at an average 10% ownership level;

the Company will otherwise sell its rights for cash, or

cash plus a royalty or working interest.

In 2019, in the Gulf Coast region of Texas, we participated with Unit Petroleum in the

successful recompletion of two wells in the Wilcox Formation of the Jazz field in Polk County, Texas.

The Company has a 2.8125% working interest and a 3.768% net revenue interest in these wells and participated for approximately $45,000.

2019, the Company successfully recompleted a shallow well in the Segno field of Polk County, Texas with a 72.5% working interest at an expense of approximately $50,000.

Significant 2019 Activity

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.

1 unchanged sentence

continue development under the programs discussed above.

Proved reserves as of December 31, 2019, were 14,235 MBOE which consist of 75% proved developed reserves.

During 2019, we participated in the drilling of a total of 18 gross (1.6 net) wells that were all completed and

on-line by year-end.

Of these 18 wells, three are in our West Texas horizontal drilling program and 15 are in our Oklahoma Scoop-Stack horizontal development program.

addition, nineteen wells designated as Shut-In at year-end 2018, were brought on production:

eight wells on the CC-33 tract of

our West Texas horizontal drilling program, in which we own 49.2% interest, and six wells in Oklahoma in which we own an average of 11.56% interest.

In 2019, the Company sold or farmed-out leasehold rights through several transactions, receiving gross

proceeds of approximately $4.28 million in exchange for 444.5 net leasehold acres in Texas and New Mexico.

In 2019, the Company

acquired approximately 31 net acres in Upton County, Texas for $156,740 and 12.8% working interest in four oil and gas wells and 25% working interest in one salt water disposal well in Chambers County, Texas, for a total cost of $55,000.

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

Proved reserves as of December 31, 2020, were 10.4 MMBOE which consisted of 69% 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.

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.

We presently own producing and non-producing properties located primarily in Texas, Oklahoma, and West

Virginia, 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.

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.

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

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.

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.

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

6 unchanged sentences

Our operations

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

We currently operate 1,064 active wells, including producing, saltwater

disposal, injection, and supply wells:

132 through the Houston office, 305 through the Midland office, 188 through the Oklahoma City office and 439 through the Charleston, West Virginia 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.

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

167 through the Houston office, 331 through the Midland office, and 262 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.

The Partnerships, Trusts and Joint Ventures

5 unchanged sentences

We stopped sponsoring partnerships and trusts in 1992.

In 2018, we liquidated three of those partnerships, and today there are only 3 partnerships and 2 trusts remaining.

The aggregate number of limited partners in the Partnerships and beneficial owners of the Trusts now administered by PEMC is

approximately 168.

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.

Regulation of the Oil and Natural Gas Industry

13 unchanged sentences

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.

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.

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

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

substantial penalties.

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

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

11 unchanged sentences

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.

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.

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.

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.

Further, state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.

5 unchanged sentences

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 statecontrolled

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 nonjurisdictional 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).

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.

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.

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).

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).

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.

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%.

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%.

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 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.

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.

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.

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.

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

18 unchanged sentences

(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 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;

(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.

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

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.

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.

(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

(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;

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.

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.

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.

The Resource Conservation and Recovery Act

14 unchanged sentences

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.

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

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.

(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

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.

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.

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.

Water Discharges

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).

Several legal challenges to the rule followed, along with attempts to stay

implementation of the WOTUS rule following the change in U.S.

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).

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.

Several groups have already announced their intent to challenge the proposed

WOTUS replacement rule.

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.

To 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.

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.

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.

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

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.

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.

Safe Drinking Water Act and Saltwater Disposal Wells

23 unchanged sentences

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.

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.

We do not believe that compliance with such requirements,

however, will have a material adverse effect on our operations.

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.

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

Regulation of Greenhouse Gas Emissions

76 unchanged sentences

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.

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

20 unchanged sentences

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.

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.

Because some of our operations are located outside major markets, we are

directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing.

The 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.

As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs.

We sell our oil and natural gas on the

open market at prevailing market prices or through forward delivery contracts.

Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing.

The market price for oil, natural gas and NGLs is dictated by supply and demand;

consequently, we cannot accurately predict or control the price we may

receive for our oil, natural gas and NGLs.

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

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.

Major Customers

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 Companys total oil and gas sales made which

represented more than 10% of the Companys oil and gas sales in the year 2019.

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 Companys total oil and gas sales made which represented more than 10% of the Companys oil and gas sales in the year 2020.

Oil Purchasers:

7 unchanged sentences

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 136 employees who were primarily involved in our district operations in Midland, Texas, Elmore City and Oklahoma City, Oklahoma and Charleston, West Virginia.

As a result of terminations in response to COVID-19 and current commodity market conditions, the

Company currently has 114 full-time employees, 28 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 86 employees who were

primarily involved in our district operations in Midland, Texas, Elmore City and Oklahoma City, Oklahoma and Charleston, West Virginia..

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.

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