What changed in this filing

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Item 2. Properties

2021-03-12 compared with 2020-03-12 · 41 added, 57 removed, 248 unchanged (28% of the section changed)

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The table below summarizes our estimated net proved reserves at December 31, 2020 and 2019 based on reports prepared by Cawley, Gillespie & Associates, Inc.

(“Cawley”), our independent reserve engineers for the year ending December 31, 2019 and 2018.

(“Cawley”), our third-party independent reserve engineers for the years ending December 31, 2020 and 2019.

In preparing its reports, Cawley evaluated properties representing all of our proved reserves at December 31, 2020 and 2019 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities.

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Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, after adjustment to reflect applicable transportation and quality differentials.

Estimated net proved reserves at December 31, 2019 were 163,307 MBoe, a 21% increase from estimated net proved reserves of 135,484 MBoe at December 31, 2018.

The increase in 2019 total proved reserves was primarily due to the impact of our 2019 acquisitions, as well as higher activity levels in 2019 as compared to 2018, offset by a decrease in commodity prices.

Increased development activity in 2019 led to an increase in our capital spending as well as an increase in the number of undeveloped drilling locations reflected in our 2019 proved reserve estimates.

As a result of the higher activity levels and our 2019 acquisitions, the number of proved undeveloped wells included in the reserves was increased from 97.9 net wells in 2018 to 107.5 net wells in 2019.

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Estimated net proved reserves at December 31, 2020 were 122,632 MBoe, a 25% decrease from estimated net proved reserves of 163,307 MBoe at December 31, 2019.

The decrease was primarily due to a 35% reduction in the SEC-prescribed oil price at year-end 2020 as compared to 2019 and a decrease in development activity.

As a result of lower demand caused by the COVID-19 pandemic and the oversupply of crude oil, spot and future prices of crude oil fell to historic lows during the second quarter of 2020, which in turn reduced development activity in the Williston Basin.

The decrease in development activity in 2020 led to a 56% reduction in our developmental capital expenditures compared to 2019 as well as a decrease in the number of undeveloped drilling locations reflected in our 2020 proved reserve estimates.

The number of proved undeveloped wells included in the reserves was reduced from 107.5 net wells in 2019 to 58.8 net wells in 2020.

The following table sets forth summary information by reserve category with respect to estimated proved reserves at December 31, 2020:

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Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

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The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2020 to the Standardized Measure of discounted future net cash flows.

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Standardized Measure of Discounted Future Net Cash Flows $ 712,010

(1) The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows.As a result of available net operating loss carryforwards and the remaining tax basis of our assets at December 31, 2019, our future income taxes were reduced.

(1) The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows.

As a result of available net operating loss carryforwards and the remaining tax basis of our assets at December 31, 2020, our future income taxes were significantly reduced.

Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control.

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Added from Extensions and Discoveries 5.6

Purchases of Minerals in Place 13.6

Removed for 5-Year Rule (2.8)

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Estimated Proved Undeveloped Reserves at 12/31/2020 38.5

During 2019, we grew our asset base through acquisitions.

In addition, we had higher development capital spending during 2019 than the prior year.

We expect to maintain similar levels of development capital spending in 2020.

As a result, we have an increased amount of proved undeveloped reserves.

Our future development drilling program includes the drilling of approximately 58.8 proven undeveloped net wells before the end of 2025 at an estimated cost of $341.0 million.

Our development plan for drilling proved undeveloped wells calls for the drilling of 44.0 net wells during 2020 (includes 16.9 net wells drilled at December 31, 2019, but classified as proved undeveloped due to Cawley’s internal guidelines which require greater than 50% of total costs to be incurred to be classified as developed), 18.2 net wells during 2021, 13.0 net wells during 2022, 15.1 net wells during 2023 and 17.2 net wells during 2024 for a total of 107.5 net wells.

Our development plan for drilling proved undeveloped wells calls for the drilling of 22.8 net wells during 2021 (includes 13.6 net wells drilled at December 31, 2020, but classified as proved undeveloped due to Cawley’s internal guidelines which require greater than 50% of total costs to be incurred to be classified as developed), 13.3 net wells during 2022, 10.5 net wells during 2023 and 12.2 net wells during 2024 for a total of 58.8 net wells.

Our proved undeveloped locations were reduced from 107.5 net wells at December 31, 2019 to 58.8 net wells at December 31, 2020 due to lower commodity prices and reduced development activity.

We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled including our acreage.

All locations comprising our remaining proved undeveloped reserves are forecast to be drilled within five years from initially being recorded in accordance with our development plan.

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At December 31, 2020, the PV-10 value of our proved undeveloped reserves amounted to 14% of the PV-10 value of our total proved reserves.

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financial targets such as drilling within cash flow or reducing debt, drilling of obligatory wells, satisfactory rates of return on proposed drilling projects, and the levels of drilling activities by operators in areas where we hold leasehold interests.

During 2019, we increased our development capital spending by 41% compared to 2018.

With 69% of the PV-10 value of our total proved reserves supported by producing wells, we believe we will have sufficient cash flows and adequate liquidity to complete our development plan.

During 2020, we decreased our development capital spending by 56% compared to 2019.

With 72% of the PV-10

value of our total proved reserves supported by producing wells, we believe we will have sufficient cash flows and adequate liquidity to execute our development plan.

At December 31, 2020, we had spent a total of $69.9 million related to the development of proved undeveloped reserves, which resulted in the conversion of 10.4 MMBoe of proved undeveloped reserves as of December 31, 2019 to proved developed reserves as of December 31, 2020.

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Additionally, our proved undeveloped reserves at December 31, 2020 included 8.2 MMBoe for net wells that had commenced drilling activities but remained classified as undeveloped reserves due to Cawley’s internal guidelines which require greater than 50% of the total costs to have been incurred in order to be classified as proved developed (the related development costs incurred at December 31, 2020 were $20.5 million).

In 2019, we also added 12.3 MMBoe of proved undeveloped reserves primarily in our North Dakota areas of operations as a result of higher commodity prices and increased well performance and development activity in the Williston Basin.

In 2020, we also added 5.6 MMBoe of proved undeveloped reserves as a result of our acquisition and development activity.

The SEC-prescribed commodity prices (after adjustment for transportation, quality and basis differentials) were $17.84 lower per barrel of oil and $0.51 lower per Mcf of natural gas at year-end 2020 as compared to year-end 2019.

Additionally, we had negative revisions of 2.3 MMBoe due to lower pricing, partially offset by positive performance revisions due to improved well performance.

Our acquisitions of oil and natural gas properties in 2019 resulted in 13.6 MMBoe of additional proved undeveloped reserves.

Additionally, we had negative revisions of 20.6 MMBoe primarily due to the aforementioned lower pricing.

We also removed 2.8 MMBoe of proved undeveloped reserves due to the SEC-prescribed 5-year rule.

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We have chosen to compare our proved reserves from the 2020 SEC case to two alternate pricing cases.

The first case scenario uses a flat pricing deck of $50.00 per Bbl for oil and $2.50 per MMbtu for natural gas (the “$50 Flat Case”).

The second case scenario uses a flat pricing deck of $60.00 per Bbl for oil and $2.50 per MMbtu for natural gas (the “$60 Flat Case”).

The first alternate scenario uses a flat pricing deck of $50.00 per Bbl for oil and $2.50 per MMbtu for natural gas (the “$50 Flat Case”).

The second alternate scenario uses a flat pricing deck of $60.00 per Bbl for oil and $2.50 per MMbtu for natural gas (the “$60 Flat Case”).

The sensitivity scenarios were not audited by a third party.

In these sensitivity scenarios, all factors other than the commodity price assumptions have been held constant with the SEC case, including the number of proved undeveloped locations, drill schedules and operating costs assumptions.

In these sensitivity scenarios, all operating cost assumptions and other factors, other than the commodity price assumptions, have been held constant with the SEC case.

However, the higher pricing in the sensitivity scenarios did result in additional future drilling locations that became economic under the $50 Flat Case and the $60 Flat Case, while they were not economic under the 2020 SEC case.

As a result, the $50 Flat Case and the $60 Flat Case included an additional 24.4 and 44.6 proved undeveloped net wells, respectively, compared to the 58.8 proved undeveloped net wells included in the 2020 SEC case.

These sensitivities are only meant to demonstrate the impact that changing commodity prices may have on estimated proved reserves and PV-10 and there is no assurance these outcomes will be realized.

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$ 712,536 $ 1,329,389 $ 1,931,094

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_________________

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(2) Prices based on $50.00 per Bbl for oil and $2.50 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $43.06 per Bbl for oil and $2.00 per Mcf for natural gas.

Production costs and the future development drilling program were both held constant with the SEC case.

(3) Prices based on $60.00 per Bbl for oil and $2.50 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $53.04 per Bbl for oil and $1.84 per Mcf for natural gas.

Production costs and the future development drilling program were both held constant with the SEC case.

(4) Pre-tax PV10%, or PV-10, may be considered a non-GAAP financial measure.

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As a result, estimates of different engineers, including those used by us, may vary.

In addition, estimates of reserves are subject to revision based upon actual

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production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors.

In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors.

The revisions may be material.

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Our senior internal reserve engineer has a B.S.

in petroleum engineering from Montana Tech, has over fourteen years of oil and gas experience on the reservoir side, and has experience working for large independent and financial firms on projects and acquisitions.

in petroleum engineering from Montana Tech, has over fifteen years of oil and gas experience on the reservoir side, and has experience working for large independent and financial firms on projects and acquisitions.

Our technical team meets with our independent third-party engineering firm to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Years Ended December 31,

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Oil (per Bbl) $ 32.61 $ 50.74 $ 57.78

Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl) 3.92 (2.94) 0.83

Oil Net of Settled Derivatives (per Bbl) 54.66 54.84 45.92

Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl) 20.08 3.92 (2.94)

Oil Net of Settled Oil Derivatives (per Bbl) 52.69 54.66 54.84

Natural Gas and NGLs (per Mcf) 1.14 1.60 4.74

Realized Price on a Boe Basis Including all Realized Derivative Settlements 45.82 50.50 42.16

Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.02 — —

Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) 1.16 1.60 4.74

Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 26.77 42.67 52.95

Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) 15.55 3.15 (2.45)

Realized Price on a Boe Basis Including Settled Commodity Derivatives 42.32 45.82 50.50

Average Costs:

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The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated.

We have classified all wells drilled to-date targeting the Bakken and Three Forks formations as development wells.

2020 2019 2018

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Gross Net (1)

Exploratory Wells:

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(1) Net Well totals in 2020, 2019 and 2018 do not include an additional 1.0, 90.1 and 65.8 net wells, respectively, from acquisitions which were already producing when acquired.

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The following table summarizes our cumulative gross and net productive oil wells by state at each of December 31, 2019, 2018 and 2017.

The following table summarizes our cumulative gross and net productive oil wells by geographic area within the United States at each of December 31, 2020, 2019 and 2018.

2020 2019 2018

Gross Net Gross Net Gross Net

North Dakota 6,033 444.4 4,693 314.1 3,172 218.7

Montana and Other 123 14.3 99 11.0 90 10.3

Williston Basin 6,633 474.5 6,156 458.7 4,792 325.1

Permian Basin 7 0.6 — — — —

Total 6,640 475.1 6,156 458.7 4,792 325.1

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Leasehold Properties

As of December 31, 2019, our principal assets included approximately 182,854 net acres located in the northern region of the United States.

The following table summarizes our estimated gross and net developed and undeveloped acreage by state at December 31, 2019.

As of December 31, 2020, our principal assets included approximately 183,527 net acres located in the United States.

The following table summarizes our estimated gross and net developed and undeveloped acreage by geographic area at December 31, 2020.

Developed Acreage Undeveloped Acreage Total Acreage

Gross Net Gross Net Gross Net

North Dakota:

McKenzie County 136,922 39,106 15,516 10,507 152,438 49,613

Mountrail County 184,654 36,625 4,670 666 189,324 37,291

Williams County 123,394 26,147 6,015 2,204 129,409 28,351

Dunn County 62,311 16,979 3,925 262 66,236 17,241

Divide County 63,116 16,285 720 226 63,836 16,511

Other 96,818 16,765 2,597 362 99,415 17,127

North Dakota 667,215 151,907 33,443 14,227 700,658 166,134

Montana and Other 54,455 12,159 6,364 4,561 60,819 16,720

Williston Basin 747,159 164,419 41,141 18,823 788,300 183,242

Permian Basin 919 229 400 56 1,319 285

748,078 164,648 41,541 18,879 789,619 183,527

As of December 31, 2020, approximately 90% of our total acreage was developed.

All of our proved reserves are located in the United States Williston Basin.

All of our proved reserves are located in the United States.

Recent Acquisitions

See Note 3 to our financial statements regarding our recent acquisitions, including the VEN Bakken Acquisition completed in 2019, and our W Energy, Pivotal and Salt Creek Acquisitions completed in 2018.

We generally assess acreage subject to near-term drilling activities on a lease-by-lease basis because we believe each lease’s contribution to a subject spacing unit is best assessed on that basis if development timing is sufficiently clear.

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In those instances, we still review each lease on a lease-by-lease basis to ensure that the package as a whole meets our acquisition criteria and drilling expectations.

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See Note 3 to our financial statements regarding our recent acquisition activity.

Acreage Expirations

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Total 41,541 18,879

During 2019, we had leases expire covering approximately 3,536 net acres, all of which was prospective for the Bakken and Three Forks Formations.

During 2020, we had leases expire covering approximately 1,720 net acres.

The 2020 lease expirations carried a cost of $2.9 million.

We believe that the expired acreage was not material to our capital deployed in these prospects.

We believe that the expired acreage was not material to our capital deployed.

Unproved Properties

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The following table presents our depletion expenses during 2020, 2019 and 2018.

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Years Ended December 31,

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Mine Safety Disclosures

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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 2. Properties