xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2019
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to____________
Commission File No. 001-33999
NORTHERN OIL AND GAS, INC.
(Exact Name of Registrant as Specified in Its Charter)
(State or Other Jurisdiction of Incorporation or Organization)
(I.R.S. Employer Identification No.)
601 Carlson Pkwy – Suite 990
Minnetonka, Minnesota 55305
(Address of Principal Executive Offices)
(Registrant’s Telephone Number)
(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically every interactive data file required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
Large Accelerated Filer ¨
Accelerated Filer x
Non-Accelerated Filer ¨
Smaller Reporting Company ¨
Emerging Growth Company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock, par value $0.001
As of May 7, 2019, there were 382,198,300shares of our common stock, par value $0.001, outstanding.
Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit. Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
The following definitions shall apply to the technical terms used in this report.
Terms used to describe quantities of crude oil and natural gas:
“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.
“Boe.” A barrel of oil equivalent and is a standard convention used to express crude oil, NGL and natural gas volumes on a comparable crude oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil or NGL.
“Boepd.”Boe per day.
“Btu or British Thermal Unit.” The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
“MBbl.” One thousand barrels of crude oil, condensate or NGLs.
“MBoe.” One thousand Boe.
“Mcf.” One thousand cubic feet of natural gas.
“MMBbl.” One million barrels of crude oil, condensate or NGLs.
“MMBoe.” One million Boe.
“MMBtu.” One million British Thermal Units.
“MMcf.” One million cubic feet of natural gas.
“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.
Terms used to describe our interests in wells and acreage:
“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs, and/or natural gas.
“Conventional play.” An area that is believed to be capable of producing crude oil, NGLs, and natural gas occurring in discrete accumulations in structural and stratigraphic traps.
“Costless Collar.”An option position where the proceeds from the sale of a call option at its inception fund the purchase of a put option at its inception.
“Developed acreage.” Acreage consisting of leased acres spaced or assignable to productive wells. Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.
“Development well.” A well drilled within the proved area of a crude oil, NGL, or natural gas reservoir to the depth of a stratigraphic horizon (rock layer or formation) known to be productive for the purpose of extracting proved crude oil, NGL, or natural gas reserves.
“Differential.” The difference between a benchmark price of crude oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“Exploratory well.” A well drilled to find and produce crude oil, NGLs, or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil, NGLs, or natural gas in another reservoir, or to extend a known reservoir.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.
“Gross acres or Gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.
“Held by operations.” A provision in an oil and gas lease that extends the stated term of the lease as long as drilling operations are ongoing on the property.
“Held by production.” A provision in an oil and gas lease that extends the stated term of the lease as long as the property produces a minimum quantity of crude oil, NGLs, and natural gas.
“Hydraulic fracturing.” The technique of improving a well’s production by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.
“Infill well.” A subsequent well drilled in an established spacing unit of an already established productive well in the spacing unit. Acreage on which infill wells are drilled is considered developed commencing with the initial productive well established in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.
“Net acres.” The percentage ownership of gross acres. Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).
“Net well.” A well that is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.
“NYMEX.” The New York Mercantile Exchange.
“OPEC.” The Organization of Petroleum Exporting Countries.
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“Recompletion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible crude oil, NGLs and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“Unconventional play.” An area believed to be capable of producing crude oil, NGLs, and/or natural gas occurring in cumulations that are regionally extensive but require recently developed technologies to achieve profitability. These areas tend to have low permeability and may be closely associated with source rock as this is the case with crude oil and natural gas shale, tight crude oil and natural gas sands and coal bed methane.
“Undeveloped acreage.” Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil, NGLs, and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage includes net acres held by operations until a productive well is established in the spacing unit.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Wellbore.” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.
“West Texas Intermediate or WTI.” A light, sweet blend of oil produced from the fields in West Texas.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own crude oil, NGLs, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
“Workover.” Operations on a producing well to restore or increase production.
Terms used to assign a present value to or to classify our reserves:
“Possible reserves.” The additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.
“Pre-tax PV-10% or PV-10.” The estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.
“Probable reserves.” The additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which together with proved reserves, are as likely as not to be recovered.
“Proved developed producing reserves (PDPs).” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional crude oil, NGLs, and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
“Proved developed non-producing reserves (PDNPs).”Proved crude oil, NGLs, and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.
“Proved reserves.” The quantities of crude oil, NGLs and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.
“Proved undeveloped drilling location.” A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
“Proved undeveloped reserves” or“PUDs.” Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves will not be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir or an analogous reservoir.
(i) The area of the reservoir considered as proved includes: (A) the area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil, NGLs or natural gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) the project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions.
“Standardized measure.” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
Northern Oil and Gas, Inc. (the “Company,” “Northern,” “our” and words of similar import), a Delaware corporation, is an independent energy company engaged in the acquisition, exploration, exploitation, development and production of crude oil and natural gas properties.The Company’s common stock trades on the NYSE American market under the symbol “NOG”.
Northern’s principal business is crude oil and natural gas exploration, development, and production with operations in North Dakota and Montana that primarily target the Bakken and Three Forks formations in the Williston Basin of the United States.The Company acquires leasehold interests that comprise of non-operated working interests in wells and in drilling projects within its area of operations.
For the three months ended March 31, 2019, crude oil accounted for 82% of the Company’s total production and 93% of its oil and gas sales.
NOTE 2 BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The financial information included herein is unaudited. The balance sheet as of December 31, 2018 has been derived from the Company’s audited financial statements for the year ended December 31, 2018. However, such information includes all adjustments (consisting of normal recurring adjustments and change in accounting principles) that are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.
Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”). The condensed financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2018, which were included in the Company’s 2018 Annual Report on Form 10-K for the fiscal year ended December 31, 2018.
The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved crude oil and natural gas reserves, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, fair value of contingent consideration, acquisition date fair values of assets acquired and liabilities assumed, impairment of oil and natural gas properties, asset retirement obligations and deferred income taxes. Actual results may differ from those estimates.
Adopted and Recently Issued Accounting Pronouncements
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”). The objective of this ASU is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB ASC Topic 842 – Leases (“ASC 842”). ASC 842 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The standard permits retrospective application through recognition of a cumulative-effect adjustment at the beginning of either the earliest reporting period presented or the period of adoption. ASC 842 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources. The Company adopted ASC 842 effective January 1, 2019 using the modified retrospective method as of the adoption date. The Company has completed the assessment of its existing accounting policies and enhancement of its internal controls. The standard did not have a material impact on the Company’s statement of operations or cash flows.
The Company’s revenues are primarily derived from its interests in the sale of oil and natural gas production. The Company recognizes revenue from its interests in the sales of oil and natural gas in the period that its performance obligations are satisfied. Performance obligations are satisfied when the customer obtains control of product, when the Company has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sales of oil and natural gas are made under contracts which the third-party operators of the wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company receives payment from the sale of oil and natural gas production from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in trade receivables, net in the balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant. Accordingly, the variable consideration is not constrained.
The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
The Company’s oil is typically sold at delivery points under contracts terms that are common in our industry. The Company’s natural gas produced is delivered by the well operators to various purchasers at agreed upon delivery points under a limited number of contract types that are also common in our industry. Regardless of the contract type, the terms of these contracts compensate the well operators for the value of the oil and natural gas at specified prices, and then the well operators will remit payment to the Company for its share in the value of the oil and natural gas sold.
A wellhead imbalance liability equal to the Company’s share is recorded to the extent that the Company’s well operators have sold volumes in excess of its share of remaining reserves in an underlying property. However, for the three months ended March 31, 2019 and 2018, the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells.
The Company’s disaggregated revenue has two revenue sources which are oil sales and natural gas and NGL sales and only operates in one geographic area, the Williston Basin in North Dakota and Montana. Oil sales for the three months ended March 31, 2019 and 2018 were $123.6 million and $79.1 million, respectively. Natural gas and NGL sales for the three months ended March 31, 2019 and 2018 were $9.1 million and $7.7 million, respectively.
Net Income (Loss) Per Common Share
Basic earnings per share (“EPS”) are computed by dividing net income (loss) (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income (loss) by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options and restricted stock. The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method.
The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2019 and 2018 are as follows:
Weighted Average Common Shares Outstanding – Basic
Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock
Weighted Average Common Shares Outstanding – Diluted
Net Income (Loss) per Common Share
During three months ended March 31, 2019, the Company had a net loss and therefore the diluted net income (loss) per common share calculation for that period excludes the anti-diluted effect of 1,278,489 shares of restricted stock awards.
During three months ended March 31, 2018, the diluted net income (loss) per common share calculation for that period excludes the anti-diluted effect of 21,820 shares of restricted stock awards and 45,206 common shares for stock options.
Supplemental Cash Flow Information
The following reflects the Company’s supplemental cash flow information:
Three Months Ended March 31,
Supplemental Cash Items:
Cash Paid During the Period for Interest
Cash Paid During the Period for Income Taxes
Non-cash Investing Activities:
Oil and Natural Gas Properties Included in Accounts Payable
Capitalized Asset Retirement Obligations
Compensation Capitalized on Oil and Gas Properties
Non-cash Financing Activities:
Issuance of 8.50% Second Lien Notes due 2023 - PIK Interest
Contingent Consideration Settlements
NOTE 3 CRUDE OIL AND NATURAL GAS PROPERTIES
The value of the Company’s crude oil and natural gas properties consists of all acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying condensed statements of operations from the closing date of the acquisition. Acquired assets and liabilities assumed are recorded based on their estimated fair value at the time of the acquisition. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. Development capital expenditures and purchases of properties that were in accounts payable and not yet paid in cash at March 31, 2019 and December 31, 2018 were $133.9 million and $129.5 million, respectively.
The Company acquired oil and natural gas properties, through a number of independent transactions, for a total of $8.4 million during the three months ended March 31, 2019.
W Energy Acquisition
On July 27, 2018, the Company entered into a purchase and sale agreement, which was subsequently amended on September 25, 2018 (as amended, the “W Energy Purchase Agreement”), with WR Operating LLC (“W Energy”), to acquire, effective as of July 1, 2018, approximately 27.2 net producing wells and 5.9 net wells in progress, as well as approximately 10,633 net acres in North Dakota (the “W Energy Acquisition”). On October 1, 2018, the Company closed on the acquisition for total estimated consideration of $341.6 million, consisting of (i) $97.8 million in cash (which reflects the $117.1 million in cash consideration under the W Energy Purchase Agreement, less $2.2 million of working capital adjustments made at closing and $17.0 million of additional estimated post-closing working capital adjustments), (ii) 51,476,961 shares of Company common stock valued at $220.8 million, based on the $4.29 per share closing price of Company common stock on the closing date of the acquisition, and (iii) $23.0 million in value attributable to potential additional contingent consideration in the future (described in more detail below). No material transaction costs were incurred in connection with this acquisition. The following table reflects a preliminary estimate of the fair values of the net assets and liabilities as of the date of acquisition, which remain subject to customary post-closing adjustments:
Fair value of net assets:
Proved oil and natural gas properties
Asset retirement cost
Total assets acquired
Asset retirement obligations
Net assets acquired
Fair value of consideration paid for net assets:
Issuance of common stock (51.5 million shares at $4.29 per share)
Total fair value of consideration transferred
A contingent consideration liability arising from potential additional consideration in connection with the W Energy Acquisition has been recognized at its fair value. The amount of additional contingent consideration payable by the Company, if any, is dependent upon the performance of the Company’s share price over a thirteen month period ending with October 2019. The acquisition date fair value of the potential additional consideration, totaling $23.0 million, was recorded within contingent consideration liabilities on the Company’s condensed balance sheets. Changes in the fair value of the liability (that were not accounted for as revisions of the acquisition date fair value) are recorded in other income (expense) on the Company’s condensed statement of operations.
On July 17, 2018, the Company entered into purchase and sale agreements with Pivotal Williston Basin, LP and Pivotal Williston Basin LP, II, to acquire approximately 20.8 net producing wells and 2.2 net wells in process, as well as approximately 444 net acres in North Dakota (the “Pivotal Acquisition”). On September 17, 2018, the Company closed on the acquisition for total estimated consideration of $146.1 million, consisting of (i) $48.2 million in cash (which reflects the $68.4 million of aggregate cash consideration provided for in the purchase agreements, less $7.8 million of working capital adjustments made at closing and $12.4 million of additional estimated post-closing working capital adjustments), (ii) 25,753,578 shares of the Company’s common stock valued at $88.6 million, based on the $3.44 per share closing price of the Company’s common stock on the closing date of the acquisition, and (iii) $9.4 million in value attributable to potential additional contingent consideration (described in more detail below).No material transaction costs were incurred in connection with this acquisition. The
following table reflects a preliminary estimate of the fair values of the net assets and liabilities as of the date of acquisition, which are subject to customary post-closing adjustments:
Fair value of net assets:
Proved oil and natural gas properties
Asset retirement cost
Total assets acquired
Asset retirement obligations
Net assets acquired
Fair value of consideration paid for net assets:
Issuance of common stock (25.8 million shares at $3.44 per share)
Total fair value of consideration transferred
A contingent consideration liability arising from potential additional consideration in connection with the Pivotal Acquisition has been recognized at its fair value. The amount of additional contingent consideration payable by the Company, if any, is dependent upon the performance of the Company’s share price over a thirteen month period ending with October 2019. The acquisition date fair value of the potential additional consideration, totaling $9.4 million, was recorded within contingent consideration liabilities on the Company’s condensed balance sheets. Changes in the fair value of the liability (that were not accounted for as revisions of the acquisition date fair value) are recorded in other income (expense) on the Company’s condensed statement of operations.
The following summarized unaudited pro forma condensed statement of operations information for the three months ended March 31, 2018assumes that both the W Energy Acquisition and the Pivotal Acquisition occurred as of January 1, 2017.The Company prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had the Company completed both of these acquisitions as of January 1, 2017, or that would be attained in the future.
Salt Creek Acquisition
On April 25, 2018, the Company entered into a purchase and sale agreement with Salt Creek Oil and Gas, LLC, to acquire 64 gross, 5.5 net producing (PDP) wells, 31 gross, 1.5 net drilling and completing (PDNP) wells and 1,319 net acres located in McKenzie and Mountrail counties of North Dakota. On June 4, 2018, the Company closed the transaction for consideration of $60.0 million which is comprised of $44.7 million of cash consideration and $15.2 million of common stock consideration. No material transaction costs were incurred in connection with this acquisition. The following table reflects a preliminary estimate of the fair values of the net assets and liabilities as of the date of acquisition, which are subject to customary post-closing adjustments:
Issuance of common stock (6.0 million shares at $2.54 per share)
Total fair value of consideration transferred
All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion. Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion.
The Company historically has acquired unproved properties by purchasing individual or small groups of leases directly from mineral owners, landmen, or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. The Company generally participates in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling.
The Company believes that the majority of its unproved costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves.
Capitalized costs associated with impaired unproved properties and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized on the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations. For the three months ended March 31, 2019 and 2018, the Company expired leases of $0.7 million and $3.8 million, respectively.
The Company’s long-term debt consists of the following:
March 31, 2019
Debt Issuance Costs, Net
Long-term Debt, Net
Second Lien Notes due 2023
Revolving Credit Facility(1)
December 31, 2018
Debt Issuance Costs, Net
Long-term Debt, Net
Second Lien Notes due 2023
Revolving Credit Facility(1)
(1)Debt issuance costs related to the Company’s revolving credit facility of $4.9 million and $5.1 million as of March 31, 2019 and December 31, 2018, respectively, are recorded in “Other Noncurrent Assets, Net” on the balance sheets.
Revolving Credit Facility
On October 5, 2018, the Company entered into a new $750.0 million revolving credit facility (the “Revolving Credit Facility”) with Royal Bank of Canada, as administrative agent, and the lenders from time to time party thereto. The revolving credit agreement is scheduled to mature 5 years from the closing date, provided that the maturity date shall be 91 days prior to the scheduled maturity date of the Second Lien Notes (defined below).
The revolving credit agreement is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to the Company and its subsidiaries’ (if any) oil and gas properties. The borrowing base as of March 31, 2019 was $425.0 million, which is the maximum amount of borrowings that the indenture for the Second Lien Notes permits the Company to have outstanding under the Revolving Credit Facility. The borrowing base will be redetermined semiannually on or around April 1st and October 1st, with one interim “wildcard” redetermination available between scheduled redeterminations. The April 1st scheduled redetermination shall be based on a January 1st engineering report audited by a 3rd party (reasonably acceptable by the Agent).
At the Company’s option, borrowings under the revolving credit agreement shall bear interest at the base rate or LIBOR plus an applicable margin. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points. The applicable margin for base rate loans ranges from 75 to 175 basis points, and the applicable margin for LIBOR loans ranges from 175 to 275 basis points, in each case depending on the percentage of the borrowing base utilized.
The revolving credit agreement contains negative covenants that limit the Company’s ability, among other things, to pay dividends, incur additional indebtedness, sell assets, enter into certain derivatives contracts, change the nature of its business or operations, merge, consolidate, or make certain types of investments. In addition, the revolving credit agreement requires that the Company comply with the following financial covenants: (i) as of the date of determination, the ratio of total net debt to EBITDAX (as defined in the revolving credit agreement) shall be no more than 4.00 to 1.00, measured on a pro forma rolling four quarter basis, and (ii) the current ratio (defined as consolidated current assets including unused amounts of the total commitments, but excluding non-cash assets under ASC 815, divided by consolidated current liabilities excluding current non-cash obligations under ASC 815 and current maturities under the revolving credit agreement and the Second Lien Notes (as defined in the revolving credit agreement)) is not permitted to be less than 1.00.
The Company’s obligations under the revolving credit agreement may be accelerated, subject to customary grace and cure periods, upon the occurrence of certain Events of Default (as defined in the revolving credit agreement). Such Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of us or the Company’s subsidiaries, defaults related to judgments and the occurrence of a Change in Control (as defined in the revolving credit agreement).
The Company’s obligations under the Revolving Credit Facility are secured by mortgages on not less than 85.0% of the value of proven reserves associated with the oil and gas properties included in the determination of the borrowing base. Additionally, the Company entered into a Guaranty and Collateral Agreement in favor of the Agent for the secured parties, pursuant to which the Company’s obligations under the revolving credit agreement are secured by a first priority security interest in substantially all of the Company’s assets.
Second Lien Notes due 2023
On May 15, 2018, the Company issued 8.500% senior secured second lien notes due 2023 (the “Second Lien Notes”) with an aggregate principal amount of $344.3 million (the “Original 2L Notes”) in exchange for certain previously outstanding 8.000% senior unsecured notes due June 1, 2020 (the “Unsecured Notes”). On October 5, 2018, the Company issued an additional $350.0 million aggregate principal amount of Second Lien Notes (the “Additional 2L Notes”), the proceeds of which were used in connection with the retirement of the Company’s prior term loan credit agreement. In addition, as of and through December 31, 2018 and March 31, 2019, the Company had issued another $0.9 million and $1.7 million, respectively, of additional aggregate principal amount of Second Lien Notes pursuant to the interest payment-in-kind provisions thereof.
The terms of the Second Lien Notes include those stated in the Indenture entered into on May 15, 2018 by the Company and Wilmington Trust, National Association, as trustee (the “Original 2L Indenture”), as amended by the First Supplemental Indenture, dated September 18, 2018 (the “First Supplemental 2L Indenture”), and the Second Supplemental Indenture, dated October 5, 2018 (the “Second Supplemental 2L Indenture” and, together with the Original 2L Indenture and the First Supplemental 2L Indenture, the “2L Indenture”).
The Second Lien Notes are the senior secured obligations of the Company and rank equal in right of payment to all existing and future senior indebtedness of the Company and its subsidiaries. The Second Lien Notes are secured by second priority security interests in substantially all assets of the Company, subject to certain exceptions. The Second Lien Notes will be guaranteed by all of the Company’s direct and indirect subsidiaries that guarantee indebtedness under any other indebtedness for borrowed money of the Company or any of the Company’s subsidiary guarantors. As of March 31, 2019, the Company did not have any subsidiaries. The Second Lien Notes will mature on May 15, 2023.
Interest on the Second Lien Notes accrues at a rate of 8.500% per annum payable in cash quarterly in arrears on the first day of each calendar quarter. Beginning on July 1, 2018, the interest rate will be increased by 1.000% per annum, which increase shall be payable in kind (the “PIK Component”). Commencing June 30, 2018, and as of each December 31st and June 30th thereafter, if the Company’s total debt to EBITDAX ratio is (i) less than 3.00 to 1.00 as of such date, the PIK Component shall cease accruing effective as of the next interest payment date, or (ii) greater than or equal to 3.00 to 1.00 as of such date or if the Company fails to deliver financial statements, the PIK Component shall continue to accrue (or, if then not accruing, automatically commence accruing as of the next interest payment date) and be payable quarterly. The PIK Component began accruing on June 30, 2018 and ceased accruing on March 31, 2019. Additionally, if the Company incurs junior lien or unsecured debt with a cash interest rate in excess of 9.500%, the cash rate on the Second Lien Notes will be increased by such excess. Default interest will be payable in cash on demand at the then applicable interest rate plus 3.000% per annum.
The Company may redeem all or a portion of any of the Second Lien Notes at the following redemption prices during the following time periods (plus accrued and unpaid interest on the Second Lien Notes redeemed): (i) from and after May 15, 2018 until May 15, 2021, 104%, (ii) on and after May 15, 2021 until May 15, 2022, 102%, and (iii) on and after May 15, 2022, 100%; provided that any redemption of Second Lien Notes (or the acceleration of Second Lien Notes) prior to May 15, 2020 shall also be accompanied by a make whole premium. Subject to the terms of an intercreditor agreement, the Company is also required to offer to prepay the Second Lien Notes with 100% of the net cash proceeds of asset sales, casualty events and condemnations in excess of $20.0 million not required to be used to pay down the loans under the Revolving Credit Facility, subject to customary exclusions and reinvestment provisions. Mandatory prepayment offers will be subject to payment of the make whole premium and redemption price set forth above, as applicable.
If a change of control occurs, the Company will be required to offer to repurchase the Second Lien Notes at the repurchase price of 101% of the principal amount of repurchased Second Lien Notes (subject to the prepayment provisions of the Revolving Credit Facility). The Second Lien Notes contain negative covenants that limit the Company’s ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain derivatives contracts, change the nature of its business or operations, merge, consolidate, make certain types of investments, amend other debt documents, and incur any additional debt on a subordinated or junior basis to the Revolving Credit Facility and on a senior basis to the Second Lien Notes. The Second Lien Notes do not include any financial maintenance covenants.
The obligations of the Company under the Second Lien Notes may be accelerated upon the occurrence of an Event of Default (as such term is defined in the 2L Indenture). Events of Default include customary events for a capital markets debt financing of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as such term is defined in the 2L Indenture).
NOTE 5 COMMON AND PREFERRED STOCK
The Company’s Restated Certificate of Incorporation authorizes the issuance of up to 680,000,000 shares. The shares are classified in two classes, consisting of 675,000,000 shares of common stock, par value $0.001 per share, and 5,000,000 shares of preferred stock, par value $0.001 per share. The board of directors is authorized to establish one or more series of preferred stock, setting forth the designation of each such series, and fixing the relative rights and preferences of each such series. The Company has neither designated nor issued any shares of preferred stock.
The following is a schedule of changes in the number of shares of common stock outstanding during the three months ended March 31, 2019 and the year ended December 31, 2018:
Three Months Ended March 31, 2019
Year Ended December 31, 2018
Repurchases of Common Stock
Stock Options Exercised - Net
Restricted Stock Grants
Stock Consideration for Acquisitions of Oil and Natural Gas Properties
Contingent Consideration Settlements
Other Surrenders - Tax Obligations
During the three months ended March 31, 2019, 0.2 million shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with their restricted stock awards. The total value of these shares was approximately $0.6 million, which is based on the market prices on the dates the shares were surrendered.
During the three months ended March 31, 2019, 1.2 million shares of common stock were issued by the Company to satisfy contingent consideration owed in connection with the Pivotal Acquisition (see Note 3).
In May 2011, the Company’s board of directors approved a stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.
During the three months ended March 31, 2019, the Company repurchased 5.6 million shares of its common stock under the stock repurchase program at a total cost of $16.3 million, of which $1.2 million was recorded as a settlement of contingent consideration liabilities. During the three months ended March 31, 2018, the Company did not repurchase shares of its common stock under the stock repurchase program. The Company’s accounting policy upon the repurchase of shares is to deduct its par value from common stock and to reflect any excess of cost over par value as a deduction from Additional Paid-in Capital.
NOTE 6 STOCK-BASED COMPENSATION
The Company’s 2018 Equity Incentive Plan (the “2018 Plan”), which replaced the Company’s prior 2013 Incentive Plan (the “2013 Plan”), authorized15,000,000 shares for grant under the 2018 Plan, plus the 769,775 shares remaining available for future grants under the 2013 Plan on the date the stockholders approved the 2018 Plan. No future awards will be made under the 2013 Plan. The 2013 Plan continues to govern awards that were made thereunder, which remain in effect pursuant to their terms. As of March 31, 2019, there were 12,509,575 shares available for future awards under the 2018 Plan.
The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company’s stock-based compensation awards are accounted for as equity instruments and are included in the “General and administrative” line item in the unaudited statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the “Oil and natural gas properties” line item on the unaudited balance sheets.
The 2018 Plan and 2013 Plan award types are summarized as follows:
Restricted Stock Awards
The Company issues restricted stock awards (“RSAs”) subject to various vesting conditions as compensation to executive officers, employees and directors of the Company. RSAs issued to employees and executive officers generally vest over three years, provided that any performance and/or market conditions are also met. RSAs issued to directors generally vest over one year, provided that any performance and/or market conditions are also met. For RSAs subject to service and/or performance vesting conditions, the grant-date fair value is established based on the closing price of the Company’s common stock on such date. Stock-based compensation expense for awards subject to only service conditions is recognized on a straight-line basis over the service period. Stock-based compensation expense for awards with both service and performance conditions is recognized on a graded basis only if it is probable that the performance condition will be achieved. The Company accounts for forfeitures of awards granted under these plans as they occur in determining stock-based compensation expense.
For awards subject to a market condition, the grant-date fair value is estimated using a Monte Carlo valuation model. The Company recognizes stock-based compensation expense for awards subject to market-based vesting conditions regardless of whether it becomes probable that these conditions will be achieved or not, and stock-based compensation expense for any such awards is not reversed if vesting does not actually occur. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility is calculated based on the historical volatility and implied volatility of the Company’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing these market-based awards were as follows:
During 2018, RSAs subject to service and performance-based vesting conditions were granted to employees and executive officers under the 2013 Plan. Vesting of these awards was contingent on the Company’s annualized Adjusted EBITDA as compared to specified targets for the fourth quarter of 2018. The Company assessed the probability of achieving the performance condition throughout the performance period using its internal financial forecasts. The weighted average grant date fair value of these service and performance-based RSAs was $2.70 per share. Also during 2018, RSAs subject to service and market-based vesting conditions were granted to employees, executive officers, and directors under the 2013 Plan. Vesting of these awards was and is contingent on the Company’s stock price performance relative to specified targets. The weighted average grant date fair value of these service and market-based RSAs was $1.67 per share.
During 2019, RSAs subject to service, market, and performance-based vesting conditions were granted to employees, executive officers, and directors under the 2018 Plan. Vesting of these awards is contingent on the Company’s debt-adjusted cash flow per share as compared to specified targets. The weighted average grant date fair value of these service, performance, and market-based RSAs was $0.98 per share. Also during 2019, RSAs subject to service and market-based vesting conditions were granted to employees, executive officers, and directors under the 2018 Plan. Vesting of these awards is contingent on the Company’s stock price performance relative to specified targets. The weighted average grant date fair value of these service and market-based RSAs was $1.82 per share.
The following table reflects the outstanding RSAs and activity related thereto for the three months ended March 31, 2019:
Service and Performance-based Awards
Service and Market-based Awards
Service, Performance, and Market-based Awards
Number of Shares
Weighted-average Grant Date Fair Value
Number of Shares
Weighted-average Grant Date Fair Value
Number of Shares
Weighted-average Grant Date Fair Value
Number of Shares
Weighted-average Grant Date Fair Value
Outstanding at December 31, 2018
Outstanding at March 31, 2019
At March 31, 2019, there was $8.3 million of total unrecognized compensation expense related to unvested RSAs. That cost is expected to be recognized over a weighted average period of 0.8 years. For the three months ended March 31, 2019 and 2018, the total fair value of the Company’s restricted stock awards vested was $2.0 million and $0.6 million, respectively.
The following has been recorded to stock-based compensation expense for the periods presented:
Three months ended March 31,
Restricted stock award compensation
Less amounts capitalized in oil and natural gas properties
Total stock-based compensation, net
NOTE 7 RELATED PARTY TRANSACTIONS
In January 2019, the Company repurchased 3.7 million shares of Company common stock from W Energy Partners LLC (“W Energy”) for cash consideration of $11.1 million. The repurchased shares were originally issued by the Company as partial consideration for the W Energy Acquisition described in Note 3 above. W Energy beneficially owned in excess of 5% of the Company’s outstanding common stock at the time of the repurchase transaction.
The Company’s Audit Committee is responsible for approving all transactions involving related parties, including the transaction identified above.
The Company is engaged in various proceedings incidental to the normal course of business. Due to their nature, such legal proceedings involve inherent uncertainties, including but not limited to, court rulings, negotiations between affected parties and governmental intervention. Based upon the information available to the Company and discussions with legal counsel, it is the Company’s opinion that the outcome of the various legal actions and claims that are incidental to its business will not have a material impact on the Company’s financial position, results of operations or cash flows. Such matters, however, are subject to many uncertainties, and the outcome of any matter is not predictable with assurance.
The Company’s interests in certain crude oil and natural gas leases from the State of North Dakota are subject to an ongoing dispute over the ownership of minerals underlying the bed of the Missouri River within the boundaries of the Fort Berthold Reservation. The ongoing dispute is between the State of North Dakota and three affiliated tribes, both of whom have purported to lease mineral rights in tracts of riverbed within the reservation boundaries. In the event the ongoing dispute results in a final judgment that is adverse to the Company’s interests, the Company would be required to reverse approximately $5.0 million in revenue (net of accrued taxes) that has been accrued since the first quarter of 2013 based on the Company’s purported interest in the crude oil and natural gas leases at issue. Due to the long-term nature of this title dispute, the $5.0 million in accounts receivable is included in “Other Noncurrent Assets, Net” on the condensed balance sheets. The Company fully maintains the validity of its interests in the crude oil and natural gas leases.
NOTE 9 INCOME TAXES
The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates. A valuation allowance for the Company’s deferred tax assets is established if, in management’s opinion, it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. Due to uncertainty surrounding the realization of its deferred tax assets, the Company has continued to record a valuation allowance against its net deferred tax assets.
The income tax provision (benefit) for the three months ended March 31, 2019 and 2018 consists of the following:
Three Months Ended March 31,
Current Income Tax Provision (Benefit)
Deferred Income Tax Provision (Benefit)
Total Income Tax Provision (Benefit)
Income tax provision (benefit) during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income (loss), plus any unusual or infrequently occurring items that are recorded in the interim period. The provision for the three months ended March 31, 2019, differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to income before income taxes. The lower effective tax rate in 2019 and 2018 relates to the valuation allowance placed on the net deferred tax assets, in addition to state income taxes and estimated permanent differences.
A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During 2019, in evaluating whether it was more likely than not that the Company’s net deferred tax assets were realized through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil and natural gas. Based on all the evidence available, management determined it was more likely than not that the net deferred tax assets, other than the deferred
tax asset related to the Company’s alternative minimum tax credit, were not realizable, therefore a valuation allowance of $149.6 million was recorded at March 31, 2019.
Tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards. The Company has no liabilities for unrecognized tax benefits.
The Company’s policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense. For the three months ended March 31, 2019 and 2018, the Company did not recognize any interest or penalties in its condensed statements of operations, nor did it have any interest or penalties accrued in its condensed balance sheets at March 31, 2019 and 2018 relating to unrecognized benefits.
NOTE 10 FAIR VALUE
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The Company uses a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following:
Level 1 - Quoted prices in active markets for identical assets or liabilities.
Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
Financial Assets and Liabilities
As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:
Fair Value Measurements at March 31, 2019 Using
Quoted Prices In Active Markets for Identical Assets (Liabilities) (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
Commodity Derivatives – Current Asset (crude oil price and basis swaps)