The table below presents the ~~below items affected~~weighted-average remaining lease term and weighted-average discount rate for the Company's fair value measurement disclosures in Note 9. Removed disclosure requirements that should be applied retrospectively to all periods presented are: (i) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (ii) the policy for timing of transfers between levels and (iii) the valuation processes for Level 3 fair value measurements. A modified disclosure requirement that should be applied prospectively is to clarify that the measurement uncertainty disclosure communicates information about the uncertainty in measurementoperating leases as of the reporting date. A new disclosure requirement that should be applied prospectively is to disclose the range and weighted-average of significant unobservable inputs used to develop Level 3 fair value measurements. The Company has elected to early adopt this guidance upon the issuance of the ASU and has modified its disclosures accordingly in this Quarterly Report.date presented:



	June 30, 2019
Weighted-average remaining lease term	3.85 years
Weighted-average discount rate	8.27	%

~~e. SEC disclosure update and simplification~~

~~In August 2018, the SEC issued Final Rule Release No. 33-10532,~~ ~~Disclosure Update and Simplification~~, which amends various SEC disclosure requirements that they have determined to be redundant, duplicative, overlapping, outdated or superseded. The amendments also extend the annual disclosure requirement of presenting the changes in stockholders' equity to interim periods. An analysis of changes in stockholders’ equity will now be required for the current and comparative year-to-date interim periods. The Company has incorporated certain aspects of the final rule in this Quarterly Report and will complete the implementation of the final rule in the fourth quarter of 2018.

~~Note 3—Acquisitions and divestitures~~

~~a. 2018 Acquisitions of evaluated and unevaluated oil and natural gas properties~~

During the nine months ended September 30, 2018, through multiple transactions, the Company acquired 895 net acres of additional leasehold interests and working interests in 47 producing horizontal and vertical wells in Glasscock County, Texas for an aggregate purchase price of $16.3 million, net of post-closing adjustments. These acquisitions were accounted for as asset acquisitions.

~~b. 2018 Divestitures of evaluated and unevaluated oil and natural gas properties and midstream service assets~~

During the nine months ended September 30, 2018, through multiple transactions, the Company completed the sale of 3,070 net acres and working interests in 24 producing vertical and horizontal wells and associated midstream service assets in Glasscock County and Howard County in Texas to third-party buyers for an aggregate sales price of $12.0 million, net of post-closing adjustments. Of this amount, $11.5 million, net of post-closing adjustments, was recorded as adjustments to oil and natural gas properties pursuant to the rules governing full cost accounting. A loss of $1.0 million from the sale of the associated midstream service assets was included in the line item "Loss on disposal of assets, net" in the unaudited consolidated statements of operations. Effective at the closings, the operations and cash flows of these oil and natural gas properties and midstream service assets were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. These divestitures did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results.

~~c. 2017 Medallion sale~~

Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market from the Midland Basin. Prior to the Medallion Sale (defined below), LMS held 49% of Medallion's ownership units. LMS and the third-party 51% interest-holder agreed that the voting rights of Medallion, the profit and loss sharing and the additional capital contribution requirements would be equal to the ownership unit percentage held. Additionally, Medallion required a super-majority vote of 75% for many key operating and business decisions. The Company determined that Medallion was a variable interest entity ("VIE"). However, LMS was not considered to be the primary beneficiary of the VIE because LMS did not have the power to direct the activities that most significantly affected Medallion's economic performance. As such, prior to the Medallion Sale, Medallion was accounted for under the equity method of accounting. The Company's proportionate share of Medallion's net income is reflected in the unaudited consolidated statements of operations on the "Income from equity method investee" line item.

On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC, which is owned and controlled by an affiliate of the third-party interest-holder, The Energy & Minerals Group, completed the sale of 100% of the ownership interests



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Condensed notes to the consolidated financial statements

(Unaudited)

~~in Medallion to an affiliate~~Maturities of ~~Global Infrastructure Partners ("GIP")~~operating lease liabilities

The table below reconciles the undiscounted cash flows for ~~cash consideration~~recognized operating lease liabilities for each of ~~$1.825 billion (the "Medallion Sale"). LMS' net cash proceeds for its 49% ownership interest in Medallion in 2017 were $829.6 million, before post-closing adjustments~~the first five years and ~~taxes, but after deduction of its proportionate share of fees and other expenses associated with~~ the ~~Medallion Sale. On February 1, 2018, closing adjustments were finalized and LMS received additional net cash of $1.7 million for~~ total net cash proceeds before taxes of $831.3 million. The proceeds were used to pay borrowings on the Senior Secured Credit Facility in full, to redeem the May 2022 Notes (as defined below) and for working capital purposes. The Medallion Sale closed pursuantremaining years to the ~~membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based~~operating lease liabilities recorded on GIP's realized profit at exit. There can be no assurance as to when and whether the additional consideration will be paid. The Medallion Sale did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results.

LMS has a Transportation Services Agreement (the "TA") with a wholly-owned subsidiary of Medallion under which LMS receives firm transportation of the Company's crude oil production from Reagan County and Glasscock County in Texas to Colorado City, Texas that continues to be in effect after the Medallion Sale. Historically, the Company's crude oil purchasers have fulfilled the commitment by transporting crude oil, purchased from the Company, under the TA, as agent. As a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees that would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted new revenue recognition guidance on January 1, 2018. The deferred gain is included in the unaudited consolidated balance ~~sheets in each~~sheet as of the ~~"Other current liabilities" and "Other noncurrent liabilities" line items~~date presented:



(in thousands)	June 30, 2019
Remaining 2019	$	11,279
2020	4,729
2021	2,833
2022	2,027
2023	1,259
Thereafter	3,925
Total minimum lease payments	26,052
Less: lease liability expense	(4,049		)
Present value of future minimum lease payments	22,003
Less: current operating lease liabilities	(9,948		)
Noncurrent operating lease liabilities	$	12,055

Disclosure for the period prior to adoption of ASC 842

The Company leases office space under operating leases expiring on various dates through 2027. The following table presents future minimum rental payments required as of the date presented:



(in thousands)	December 31, 2018
2019	$	3,092
2020	3,179
2021	3,128
2022	2,560
2023	1,358
Thereafter	4,556
Total future minimum rental payments required	$	17,873

The Company subleases office space with $5.9 million of total future minimum rentals to be received as of December 31, ~~2017. See Note 4.a for discussion of~~2018. For the ~~impact~~period prior to ~~the deferred gain upon~~ the adoption of ASC ~~606.~~

~~d. 2017 Divestiture of evaluated and unevaluated oil and natural gas properties~~

~~In January 2017, the Company completed the sale of 2,900 net acres and working interests~~842, rent income is included in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million. After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.5 million, net of working capital and post-closing adjustments. A significant portion of these proceeds was used to pay down borrowings"Other income, net" on the Senior Secured Credit Facility. The purchase price was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these oil and natural gas properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results.

~~e. Exchange of unevaluated oil and natural gas properties~~

From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

~~Note 4—Revenue recognition~~

~~a. Impact of ASC 606 adoption~~

Upon adoption of ASC 606 on January 1, 2018, for the three and nine months ended September 30, 2018, the Company reclassified certain firm transportation payments on excess pipeline capacity and other contractual penalties due to customers, historically included in the "Other operating expenses" line item in the unaudited consolidated statements of operations, and netted them with the revenue stream from which they derive as these payments to customers do not relate to the provision of a distinct good or service to the customer. In addition, there was an impact upon adoption related to the treatment of the gain on the Medallion Sale.operations.



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Condensed notes to the consolidated financial statements

(Unaudited)

~~The impact of the adoption of ASC 606 on the results of operations for the periods presented is as follows:~~

Three months ended September 30, 2018 Nine months ended September 30, 2018
(in thousands) As computed under ASC 605
As reported under ASC 606
Increase/(decrease) As computed under ASC 605 As reported under ASC 606 Increase/(decrease)
Revenues:
Oil sales $ 160,246
$ 160,007
$ (239 ) $ 472,496
$ 469,972
$ (2,524 )
NGL sales $ 50,814
$ 50,814
$ —
$ 115,979
$ 115,979
$ —
Natural gas sales $ 15,043
$ 15,043
$ —
$ 45,908
$ 45,908
$ —
Costs and expenses:
Other operating expenses $ 1,353
$ 1,114
$ (239 ) $ 5,865
$ 3,341
$ (2,524 )

Net income $ 55,050
$ 55,050
$ —
$ 175,022
$ 175,022
$ —

~~At December 31, 2017, the Medallion Sale was accounted for under the real estate guidance in ASC 360-20,~~ ~~Property, Plant, and Equipment~~ ("ASC 360-20"), and the Company's maximum exposure to loss associated with future commitments under the TA was $141.1 million that was not recorded in the Company's unaudited consolidated balance sheets. Under ASC 360-20, as a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees. This deferred gain would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted ASC 606 on January 1, 2018. See Note 3.c for further discussion of the Medallion Sale and the TA.

~~Upon the adoption of ASC 606, the guidance in ASC 360-20 was superseded by ASC 860,~~ ~~Transfers and Servicing~~ ("ASC 860"). The Medallion Sale is within the scope of ASC 860 and qualifies for sale accounting and recognition of the previously deferred gain because as of the date of the Medallion Sale (i) the Company transferred and legally isolated its full interests in Medallion to GIP, (ii) GIP received the right to pledge or exchange Medallion ownership interests at its full discretion and (iii) the Company did not have effective control over Medallion. Therefore, the deferred gain of $141.1 million was recognized as an adjustment to the beginning balance of accumulated deficit, presented in the unaudited consolidated statements of stockholders' equity, in accordance with the modified retrospective approach of adoption.

~~b. Revenue recognition~~

Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated through fees for products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, gas lift and water delivery, recycling and takeaway (collectively, "Midstream Services") and are recognized over time as the customer benefits from these services when provided. A more detailed summary of the underlying contracts that give rise to the Company's revenue and method of recognition is included below.

~~Oil sales and sales of purchased oil~~

Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606 typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser.

From time to time, the Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid



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~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying unaudited consolidated statements of operations.

Under certain of its customer contracts, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs.

~~NGL and natural gas sales~~

Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that we have transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense.

~~Midstream Services~~

Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate.

~~Imbalances~~

The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of September 30, 2018 or December 31, 2017.

~~Significant judgments~~

The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model in ASC 606. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue.

~~Transaction price allocated to remaining performance obligations~~

A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.



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~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

For the Company's product sales that have a contract term greater than one year and for its Midstream Services, the Company has utilized the practical expedient in ASC 606-10-50-14A that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under the Midstream Services contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied.

~~Contract balances~~

Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606.

~~Prior-period performance obligations~~

For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 to 90 days after the date production is delivered and, as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the three and nine months ended September 30, 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

Note 5—4—Property and equipment

The following table presents the Company's property and equipment as of the dates presented:



(in thousands)	June 30, 2019			December 31, 2018
Evaluated oil and natural gas properties	$	7,080,332		$	6,752,631
Less accumulated depletion and impairment	(4,975,302		)	(4,854,017		)
Evaluated oil and natural gas properties, net	2,105,030			1,898,614

Unevaluated oil and natural gas properties not being depleted	95,138			130,957

Midstream service assets	178,735			172,308
Less accumulated depreciation and impairment	(47,102		)	(42,063		)
Midstream service assets, net	131,633			130,245

Depreciable other fixed assets	44,654			45,431
Less accumulated depreciation and amortization	(24,980		)	(23,871		)
Depreciable other fixed assets, net	19,674			21,560

Land	18,259			18,259

Total property and equipment, net	$	2,369,734		$	2,199,635

(in thousands) September 30, 2018 December 31, 2017
Evaluated oil and natural gas properties $ 6,589,327
$ 6,070,940
Less accumulated depletion and impairment (4,798,527 ) (4,657,466 )
Evaluated oil and natural gas properties, net 1,790,800
1,413,474

Unevaluated oil and natural gas properties not being depleted 147,690
175,865

Midstream service assets 171,740
171,427
Less accumulated depreciation and impairment (39,325 ) (33,102 )
Midstream service assets, net 132,415
138,325

Depreciable other fixed assets 50,420
48,957
Less accumulated depreciation and amortization (26,415 ) (23,150 )
Depreciable other fixed assets, net 24,005
25,807

Land 18,259
14,914

Total property and equipment, net $ 2,113,169
$ 1,768,385

For the three months ended September 30, 2018 and 2017, depletion expense for the Company's evaluated oil and natural gas properties was $7.94 per barrel of oil equivalent ("BOE") sold and $6.80 per BOE sold, respectively. For the nine months ended September 30, 2018 and 2017, depletion expense for the Company's evaluated oil and natural gas properties was $7.67 per BOE sold and $6.57 per BOE sold, respectively.

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain ~~employee-related~~related employee costs incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite unit-of-production method based



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~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including ~~employee-related~~related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

The following table presents capitalized ~~employee-related~~related employee costs incurred for the purpose of exploring for or developing oil and natural gas properties for the periods presented:



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2019		2018		2019		2018
Capitalized related employee costs	$	3,430	$	6,735	$	10,112	$	13,264

Three months ended September 30, Nine months ended September 30,
(in thousands) 2018 2017 2018 2017
Capitalized employee-related costs $ 5,837
$ 6,938
$ 19,101
$ 17,911

The Company excludes the costs directly associated with the acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.

The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10%. The SEC guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized



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Condensed notes to the consolidated financial statements

(Unaudited)

to calculate the discounted future net revenues in the full cost ceiling calculation. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data.

In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. As the Company's Realized Prices decrease, it is reasonably possible that a material full cost ceiling impairment could occur. The unamortized cost of evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of June 30, 2019 or December 31, 2018. There were no full cost ceiling impairments recorded during the six months ended June 30, 2019 or 2018.

The following table presents the Benchmark Prices and Realized Prices as of the dates presented:



	June 30, 2019		December 31, 2018
Benchmark Prices:
Oil ($/Bbl)	$	57.90	$	62.04
NGL ($/Bbl)⁽¹⁾	$	28.21	$	31.46
Natural gas ($/MMBtu)	$	1.14	$	1.76
Realized Prices:
Oil ($/Bbl)	$	55.69	$	59.29
NGL ($/Bbl)	$	18.64	$	21.42
Natural gas ($/Mcf)	$	0.70	$	1.38

_____________________________________________________________________________


(1)	Based on the Company's average composite NGL barrel.

The Company computes the provision for depletion of oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. For the three months ended June 30, 2019 and 2018, depletion expense for the Company's evaluated oil and natural gas properties was $8.27 per barrel of oil equivalent ("BOE") sold and $7.68 per BOE sold, respectively. For the six months ended June 30, 2019 and 2018, depletion expense for the Company's evaluated oil and natural gas properties was $8.51 per BOE sold and $7.52 per BOE sold, respectively.

The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented:



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2019		2018		2019		2018
Property acquisition costs⁽¹⁾:							—
Evaluated	$	—	$	13,847	$	—	$	13,847
Unevaluated	2,880		2,790		2,880		2,790
Exploration costs	5,116		5,108		12,621		11,245
Development costs	123,664		178,796		276,381		327,834
Total costs incurred	$	131,660	$	200,541	$	291,882	$	355,716

_____________________________________________________________________________

Three months ended September 30, Nine months ended September 30,
(in thousands) 2018 2017 2018 2017
Property acquisition costs (see Note 3.a):

—
Evaluated $ —
$ —
$ 13,847
$ —
Unevaluated —
—
2,790
—
Exploration costs 7,502
7,136
18,747
28,337
Development costs 139,748
160,359
467,582
397,255
Total costs incurred $ 147,250
$ 167,495
$ 502,966
$ 425,592


(1)	See Note 3.a in the second-quarter 2018 Quarterly Report for discussion of the Company's acquisitions of evaluated and unevaluated oil and natural gas properties during the three months ended June 30, 2018.

Note 6—5—Debt

a. March 2023 Notes

On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"). The March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis



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Condensed notes to the consolidated financial statements

(Unaudited)

by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases"). The Company may redeem, at its option, all or part of the March 2023 Notes at any time ~~after March 15, 2018,~~ at a price of ~~104.688%~~103.125% of face value with call premiums declining annually to 100% of face value on March 15, 2021 and thereafter plus accrued and unpaid interest to, but not including, the date of redemption.



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~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

b. January 2022 Notes

On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. The Company may redeem, at its option, all or part of the January 2022 Notes at any time ~~after January 15, 2018,~~ at a price of ~~102.813%~~101.406% of face value with call premiums declining ~~annually~~ to 100% of face value on January 15, 2020 and thereafter plus accrued and unpaid interest to, but not including, the date of redemption.

c. ~~May 2022 Notes~~

On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes were due to mature on May 1, 2022 and bore an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

On November 29, 2017 (the "May 2022 Notes Redemption Date"), utilizing a portion of the proceeds from the Medallion Sale, the entire $500.0 million outstanding principal amount of the May 2022 Notes was redeemed at a redemption price of 103.688% of the principal amount of the May 2022 Notes, plus accrued and unpaid interest up to, but not including, the May 2022 Notes Redemption Date. The Company recognized a loss on extinguishment of $23.8 million related to the difference between the redemption price and the net carrying amount of the extinguished May 2022 Notes.

d. Senior Secured Credit Facility

The Senior Secured Credit Facility matures on April 19, 2023, provided that if either the January 2022 Notes or March 2023 Notes have not been refinanced on or prior to the date (as applicable, the "Early Maturity Date") that is 90 days before their respective stated maturity dates, the Senior Secured Credit Facility will mature on such Early Maturity Date. As of ~~September~~June 30, ~~2018,~~2019, the Senior Secured Credit Facility had a maximum credit amount of $2.0 billion, a borrowing base ~~of $1.3 billion~~ and an aggregate elected commitment of ~~$1.2~~$1.1 billion each, with ~~$170.0~~$235.0 million outstanding and was subject to an interest rate of ~~3.44%~~3.69%. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with as of September 30, 2018. Laredo is required to pay a commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the aggregate elected commitment under the Senior Secured Credit Facility.for all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million. ~~No letters~~As of June 30, 2019 and December 31, 2018, the Company had one letter of credit ~~were~~ outstanding as of ~~September 30,~~$14.7 million under the Senior Secured Credit Facility. For additional information see Note 7.d in the 2018 ~~or December 31, 2017.~~Annual Report. See Note 1618.a for discussion of ~~items affecting~~an additional payment on the Senior Secured Credit Facility subsequent to ~~September~~June 30, ~~2018.~~2019.

e.d. Long-term debt, net

The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the unaudited consolidated balance sheets as of the dates presented:


	September 30, 2018							December 31, 2017							June 30, 2019							December 31, 2018
(in thousands)	Long-term debt		Debt issuance costs, net			Long-term debt, net		Long-term debt		Debt issuance costs, net			Long-term debt, net		Long-term debt		Debt issuance costs, net			Long-term debt, net		Long-term debt		Debt issuance costs, net			Long-term debt, net
January 2022 Notes	$	450,000	$	(3,254	)	$	446,746	$	450,000	$	(3,987	)	$	446,013	$	450,000	$	(2,522	)	$	447,478	$	450,000	$	(3,010	)	$	446,990
March 2023 Notes	350,000		(3,555		)	346,445		350,000		(4,158		)	345,842		350,000		(2,952		)	347,048		350,000		(3,354		)	346,646
Senior Secured Credit Facility⁽¹⁾	170,000		—			170,000		—		—			—		235,000		—			235,000		190,000		—			190,000
Total	$	970,000	$	(6,809	)	$	963,191	$	800,000	$	(8,145	)	$	791,855	$	1,035,000	$	(5,474	)	$	1,029,526	$	990,000	$	(6,364	)	$	983,636

______________________________________________________________________________


(1)	Debt issuance costs, net related to our Senior Secured Credit Facility of ~~$7.4~~$6.1 million and ~~$6.0~~$7.0 million as of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017,~~2018, respectively, are reported in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 7—6—Stockholders' equity and ~~stock-based compensation~~Equity Incentive Plan

a. Share repurchase program

In February 2018, the Company's board of directors authorized a $200 million share repurchase program commencing in February 2018. The repurchase program expires in February 2020. Share repurchases under the share repurchase program may be made through a variety of methods, which may include open market purchases, privately negotiated transactions and block trades. The timing and actual number of share repurchases will depend upon several factors, including market conditions, business conditions, the trading price of the Company's common stock and the nature of other investment opportunities available to the Company. During the ~~three months~~year ended September 30, 2018, the Company repurchased 1,170,190 shares of common stock at a weighted-average price of $8.41 per common share for a total of $9.9 million under this program. During the nine months ended September 30,December 31, 2018, the Company repurchased 11,048,742 shares of common stock at a weighted-average price of $8.78 per common share for a total of $97.1 million under this program. All shares were retired upon repurchase. There were no share repurchases under this program during the six months ended June 30, 2019.

b. Treasury stock

Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result from (i) share repurchases under the share repurchase program, ~~or from the withholding of shares of~~(ii) stock exchanged to satisfy ~~employee~~ tax withholding ~~obligations~~ that ~~arise~~arises upon the lapse of restrictions on ~~their stock-based~~restricted stock awards and the exercise of stock options at the ~~employees'~~awardee's election and (iii) stock exchanged for cost of exercise of stock options at the awardee's election.

c. ~~Stock-based compensation~~Equity Incentive Plan

The ~~Company's Long-Term~~Laredo Petroleum, Inc. Omnibus Equity Incentive Plan, as amended and restated as of May 16, 2019 (the ~~"LTIP"~~"Equity Incentive Plan"), provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, outperformance share awards, performance unit awards and other awards. ~~The LTIP provides for~~During the ~~issuance~~second quarter of up2019, the Company's stockholders approved an amendment to the Equity Incentive Plan, among other items, to increase the maximum number of shares of the Company's common stock issuable under the Equity Incentive Plan from 24,350,000 shares ~~of Laredo's common stock.~~to 29,850,000 shares.

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~~awards and are included in ~~the~~ "General and administrative" ~~line item in~~on the unaudited consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in ~~the~~ "Evaluated properties" ~~line item~~ on the unaudited consolidated balance sheets. The Company's performance unit awards, granted in 2019, were accounted for as liability awards and included in "General and administrative", net of amounts capitalized, in the unaudited consolidated statements of operations for the three months ended March 31, 2019, and the corresponding liabilities were included in "Other noncurrent liabilities" on the unaudited consolidated balance sheet as of March 31, 2019. Upon their modification during second quarter of 2019, the performance unit awards were converted to performance share awards and the performance unit award compensation was reversed. See "Performance share awards" and "Performance unit awards" below for additional discussion of the modification.

Restricted stock awards

All service vesting restricted stock awards are treated as issued and outstanding in the ~~accompanying~~ unaudited consolidated financial statements. Per the award agreement terms, if ~~an employee terminates~~ employment is terminated prior to the restriction lapse date for reasons other than death or disability, the ~~awarded shares~~restricted stock awards are forfeited and canceled and are no longer considered issued and outstanding. If the ~~employee's~~ termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to ~~officers and~~ employees vest in a variety of vesting schedules that mainly include (i) 33%, 33% and 34% per year beginning on the first anniversary of the grant date and (ii) fully on the first anniversary of the grant date. ~~Beginning August 2017, stock~~Stock awards granted to non-employee directors vest immediately on the grant date. ~~Restricted stock awards granted to non-employee directors prior to August 2017 vested on the first anniversary~~See Note 17 for discussion of the ~~grant date.~~

Company's organizational restructuring during the three months ended June 30, 2019.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table reflects the restricted stock award activity for the ~~nine~~six months ended ~~September~~June 30, ~~2018:~~2019:


(in thousands, except for weighted-average grant-date fair value)	Restricted stock awards		Weighted-average grant-date fair value (per award)		Restricted stock awards		Weighted-average grant-date fair value (per award)
Outstanding as of December 31, 2017	3,169		$	12.81
Outstanding as of December 31, 2018					4,196		$	9.91
Granted	3,248		$	8.42	7,050		$	3.32
Forfeited	(266	)	$	10.35	(2,811	)	$	4.99
Vested⁽¹⁾	(1,851	)	$	12.21	(2,445	)	$	9.70
Outstanding as of September 30, 2018	4,300		$	9.90
Outstanding as of June 30, 2019					5,990		$	4.55

_____________________________________________________________________________


(1)	The total intrinsic value of vested restricted stock awards for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 was ~~$16.1~~$9.2 million.

The Company utilizes the closing stock price on the grant date to determine the fair value of ~~service vesting~~ restricted stock awards. As of ~~September~~June 30, ~~2018,~~2019, unrecognized stock-based compensation related to the restricted stock awards expected to vest was ~~$26.5~~$21.8 million. Such cost is expected to be recognized over a weighted-average period of ~~1.87~~2.23 years.

Stock option awards

~~Stock~~The following table reflects the stock option ~~awards granted under~~award activity for the ~~LTIP vest and become exercisable in four equal installments on each of the four anniversaries of the grant date.~~ six months ended June 30, 2019:



(in thousands, except for weighted-average exercise price and weighted-average remaining contractual term)	Stock option awards		Weighted-average exercise price (per award)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2018	2,533		$	12.69	5.99
Exercised⁽¹⁾	(18	)	$	4.10
Expired or canceled	(49	)	$	18.45
Forfeited	(196	)	$	8.71
Outstanding as of June 30, 2019	2,270		$	12.98	3.04
Vested and exercisable as of June 30, 2019⁽²⁾	2,096		$	13.34	2.70
Expected to vest as of June 30, 2019⁽³⁾	174		$	8.72	7.11

_____________________________________________________________________________


(1)	The exercised stock option awards for the six months ended June 30, 2019 had de minimis intrinsic value.


(2)	The vested and exercisable stock option awards as of June 30, 2019 had no aggregate intrinsic value.


(3)	The expected to vest stock option awards as of June 30, 2019 had no aggregate intrinsic value.

As of ~~September~~June 30, 2018, the 2,577,205 outstanding stock option awards have a weighted-average exercise price of $12.66 and a weighted-average remaining contractual term of 6.37 years. There were de minimis exercises, forfeitures and cancellations of stock option awards during the nine months ended September 30, 2018. There were no grants of stock option awards during the nine months ended September 30, 2018.

The Company utilizes the Black-Scholes option pricing model to determine the fair value of stock option awards and recognizes the associated expense on a straight-line basis over the four-year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated expected volatility. As of September 30, 2018,2019, unrecognized stock-based compensation related to stock option awards expected to vest was ~~$5.0~~$1.1 million. Such cost is expected to be recognized over a weighted-average period of ~~1.67~~1.15 years.

See Note 17 for discussion of the Company's organizational restructuring during the three months ended June 30, 2019. See Note 8.c in the 2018 Annual Report for additional information on the stock option awards.

Performance share awards

Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For performance share awards with market criteria or portions of awards with market criteria, which ~~include~~include: (i) the relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in each award agreement ("RTSR Performance ~~Percentage (as defined below)~~Percentage"), (ii) the Company's absolute three-year total shareholder return ("ATSR ~~Appreciation (as defined below)~~Appreciation") and (iii) the Company's total shareholder return ("TSR"), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date (or modification date) fair value, and the associated expense is recognized on a straight-line basis over the three-year requisite service period of the awards. For portions of awards with performance criteria, which is the Company's three-year return on average capital employed ("ROACE ~~Percentage (as defined below)~~Percentage"), the ~~grant-date~~ fair value is equal to the Company's closing stock price on the grant date (or modification date), and for each reporting period, the associated expense fluctuates and is ~~trued-up~~adjusted based on an estimated ~~probability~~payout of ~~how many~~the number of shares ~~will~~of common stock to be ~~earned at~~delivered on the ~~end of~~payment date for the three-year performance period.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Any shares earned under performance share awards are expected to be issued in the first quarter following the completion of the respective requisite service ~~period~~periods based on the achievement of certain market and performance ~~criteria.~~



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes~~criteria, and the payout can range from 0% to 200%. Per the award agreement terms, if employment is terminated prior to the ~~consolidated financial statements~~restriction lapse date for reasons other than death or disability, the performance share awards are forfeited and canceled. If the termination of employment is by reason of death or disability, and the market and performance criteria are satisfied, then the holder of the earned performance share awards will receive a prorated number of shares based on the number of days the participant was employed with the Company during the performance period. See Note 17 for discussion of the Company's organizational restructuring during the three months ended June 30, 2019.

~~(Unaudited)~~

The following table reflects the performance share award activity for the ~~nine~~six months ended ~~September~~June 30, ~~2018:~~2019:



(in thousands, except for weighted-average grant-date fair value)	Performance share awards		Weighted-average grant-date fair value (per award)
Outstanding as of December 31, 2018	3,436		$	13.74
Granted⁽¹⁾	588		$	2.52
Converted from performance unit awards⁽¹⁾⁽²⁾	1,558		$	3.74
Forfeited	(860	)	$	12.26
Vested⁽³⁾	(1,545	)	$	17.31
Outstanding as of June 30, 2019	3,177		$	6.28

(in thousands, except for weighted-average grant-date fair value)
Performance
share
awards

Weighted-average
grant-date fair value
(per award)
Outstanding as of December 31, 2017 2,745
$ 17.77
Granted⁽¹⁾
1,389
$ 9.22
Forfeited (149 ) $ 14.83
Vested⁽²⁾
(454 ) $ 16.23
Outstanding as of September 30, 2018 3,531
$ 14.55

______________________________________________________________________________

(1)

The ~~amount of stock~~amounts potentially payable in the Company's common stock at the end of the ~~performance~~requisite service period for the performance share awards granted on February ~~16, 2018~~28, 2019 and June 3, 2019 will be determined based on three criteria: (i) ~~relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in the award agreement ("~~RTSR Performance ~~Percentage"),~~Percentage, (ii) ~~absolute three-year total shareholder return ("~~ATSR ~~Appreciation")~~Appreciation and (iii) ~~three-year return on average capital employed ("~~ROACE ~~Percentage").~~Percentage. The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the ~~final~~ number of shares ~~associated with each performance share unit granted at~~to be delivered on the ~~maturity date (with all partial shares rounded, as appropriate).~~payment date. In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The $9.22 per unit grant-date fair value consists of a (i) $10.08 per unit grant-date fair value, determined utilizing a Monte Carlo simulation, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $8.36 per unit grant-date fair value for the (.50) ROACE Factor determined based on the closing price of the Company's common stock on the New York Stock Exchange on February 16, 2018. These awards have a performance period of January 1, ~~2018~~2019 to December 31, ~~2020.~~2021.


(2)	On May 16, 2019, the board of directors elected to change the form of payment from cash to common stock for the awards granted on February 28, 2019. This change in election triggered modification accounting, and the awards, formerly accounted for as liability awards, were converted to equity awards and, accordingly, new fair values were determined based on the May 16, 2019 modification date.

(3)

The performance share awards granted on ~~February 27, 2015~~May 25, 2016 had a performance period of January 1, ~~2015~~2016 to December 31, ~~2017~~2018 and, as their ~~performance~~market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the ~~36th~~ninth percentile of its peer group for relative TSR. As such, the granted units lapsed and were not converted into the Company's common stock during the first quarter of ~~2018.~~2019.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The fair values per performance share award and the assumptions used to estimate these fair values per performance share award granted on February 28, 2019 and June 3, 2019 are as follows:



	February 28, 2019⁽¹⁾			June 3, 2019
Market criteria:
(.25) RTSR Factor + (.25) ATSR Factor fair value assumptions:
Remaining performance period	2.63 years			2.58 years
Risk-free interest rate⁽²⁾	2.14		%	1.78		%
Dividend yield	—		%	—		%
Expected volatility⁽³⁾	55.01		%	55.45		%
Closing stock price on May 16, 2019 and June 3, 2019 for the respective awards	$	3.49		$	2.59
Fair value per performance share award	$	3.98		$	2.45

Performance criteria:
(.50) ROACE Factor fair value assumption:
Closing stock price on May 16, 2019 and June 3, 2019 for the respective awards	$	3.49		$	2.59
Fair value per performance share award	$	3.49		$	2.59

Combined fair value per performance share award⁽⁴⁾	$	3.74		$	2.52

______________________________________________________________________________

(1)

The fair values of the performance share awards granted on February 28, 2019 are based on the May 16, 2019 modification date. The total incremental compensation expense resulting from the modification of $1.0 million, which will be recognized over the life of the awards, is calculated utilizing (i) the difference between the March 31, 2019 fair value and the May 16, 2019 fair value and (ii) the outstanding quantity of the converted performance share awards as of June 30, 2019. Such expense excludes the estimated payout component for expense for the (.50) ROACE Factor as this is redetermined at each reporting period and the expense will fluctuate accordingly.


(2)	The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on May 16, 2019 and June 3, 2019 for the respective awards.


(3)	The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility.


(4)	The combined fair value per performance share award is the combination of the fair value per performance share award for weighted for the market and performance criteria for the respective awards.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The expense per performance share award for the outstanding performance share awards as of June 30, 2019 and granted as of the dates presented are as follows:



	February 17, 2017		February 16, 2018			February 28, 2019			June 3, 2019
Market Criteria:
(.25) RTSR Factor + (.25) ATSR Factor:
Fair value per performance share award	Not applicable		$	10.08		$	3.98		$	2.45
Expense per performance share award as of June 30, 2019	Not applicable		$	10.08		$	3.98		$	2.45

TSR:
Fair value per performance share award	$	18.96
Expense per performance share award as of June 30, 2019	$	18.96

Performance Criteria:
(.50) ROACE Factor:
Fair value per performance share award	Not applicable		$	8.36		$	3.49		$	2.59
Estimated payout for expense as of June 30, 2019⁽¹⁾	Not applicable		60		%	195		%	195		%
Expense per performance share award as of June 30, 2019	Not applicable		$	5.02		$	6.81		$	5.05

Combined expense per performance share award as of June 30, 2019⁽²⁾	$	18.96	$	7.55		$	5.40		$	3.75

______________________________________________________________________________


(1)	As the (.50) ROACE Factor is based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the respective awards is adjusted accordingly.


(2)	The combined expense per performance share award is the combination of the expense per performance share award for market and performance criteria for the respective awards.

As of ~~September~~June 30, ~~2018,~~2019, unrecognized stock-based compensation related to the performance share awards expected to vest was ~~$18.6~~$13.3 million. Such cost is expected to be recognized over a weighted-average period of ~~1.72~~2.26 years.

Outperformance share award

An outperformance share award was granted during the three months ending June 30, 2019, in conjunction with the appointment of the Company's President, and is accounted for as an equity award. If earned, the payout ranges from 0 to 1,000,000 shares in the Company's common stock per the vesting schedule. This award is subject to a combination of market and service vesting criteria, therefore, a Monte Carlo simulation prepared by an independent third party was utilized to determine the grant-date fair value with the associated expense recognized over the requisite service period. The payout of this award is based on the highest 50 consecutive trading day average closing stock price of the Company that occurs during the performance period that commenced on June 3, 2019 and ends on June 3, 2022 ("Final Date"). Of the earned outperformance shares, one-third of the award will vest on the Final Date, one-third will vest on the first anniversary of the Final Date and one-third will vest on the second anniversary of the Final Date, provided that the participant has been continuously employed with the Company through the applicable vesting date. Per the award agreement terms, if employment is terminated prior to any vesting date for reasons other than death or disability, then any outperformance shares that have not vested as of such date shall be forfeited and canceled. If the participant's employment is terminated prior to any vesting date by reason of death or disability, and the market criteria is satisfied, then the participant will receive a pro-rated number of shares based on the number of days the employee was employed with the Company during the performance period.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The total fair value of the outperformance share award and the assumptions used to estimate the ~~combined~~ fair value ~~for the (.25) RTSR Factor and the (.25) ATSR Factor for the market criteria portion~~ of the ~~performance~~outperformance share ~~awards granted on~~award as of the grant date presented are as follows:


	February 16, 2018			June 3, 2019
Performance period				3.00 years
Risk-free interest rate⁽¹⁾	2.34		%	1.77		%
Dividend yield	—		%	—		%
Expected volatility⁽²⁾	65.49		%	55.77		%
Laredo stock closing price on grant date	$	8.36
Combined fair value per performance share award for the (.25) RTSR Factor and the (.25) ATSR Factor⁽³⁾	$	10.08
Closing stock price on grant date				$	2.59
Total fair value of outperformance share award (in thousands)				$	670

_____________________________________________________________________________


(1)	The performance period matched zero-coupon risk-free interest rate was ~~derived using a term-matched zero-coupon yield~~ derived from the U.S. Treasury constant maturities yield curve on the grant date.


(2)	The Company utilized its own performance period matched historical volatility in order to develop the expected volatility.

As of June 30, 2019, unrecognized stock-based compensation related to the outperformance share award expected to vest was $0.7 million. Such cost is expected to be recognized over a weighted-average period of 5.00 years.

Stock-based compensation expense

The following has been recorded to stock-based compensation expense for the periods presented:



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2019			2018			2019			2018
Restricted stock award compensation	$	2,559		$	7,286		$	7,882		$	13,331
Stock option award compensation	160			971			978			2,040
Performance share award compensation	(3,191		)	4,415			(27		)	8,742
Outperformance share award compensation	13			—			13			—
Total stock-based compensation, gross	(459		)	12,672			8,846			24,113
Less amounts capitalized in evaluated oil and natural gas properties	36			(1,996		)	(1,863		)	(4,098		)
Total stock-based compensation, net	$	(423	)	$	10,676		$	6,983		$	20,015

See Note 17 for discussion of the Company's organizational restructuring and the related stock-based compensation reversal during the three months ended June 30, 2019.

Performance unit awards

The performance unit awards, granted on February 28, 2019, were determined to be liability awards due to the board of directors election to settle the awards in cash. On May 16, 2019, the board of directors elected to change the form of payment from cash to common stock and, as a result, the performance unit awards were converted to performance share awards, which the Company determined were now equity awards. This change in election triggered modification accounting, and the performance unit award compensation for the three months ended March 31, 2019 was reversed and a new fair value was determined for the converted performance share awards and adjusted in stock-based compensation based on the May 16, 2019 modification date. For additional discussion of the modification, see "Performance share awards."

The following table reflects the performance unit award activity for the six months ended June 30, 2019:



~~(3)~~(in thousands)	~~The market criteria portion~~	Performance unit awards
Outstanding as of ~~the~~December 31, 2018		—
Granted		2,813
Forfeited		(1,255	)
Converted to performance share ~~award represents 50%~~awards		(1,558	)
Outstanding as of ~~each of the amount of stock potentially payable, if any, and the grant-date fair value of the award.~~June 30, 2019		—



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~Stock-based compensation expense~~

~~The following has been recorded to stock-based compensation expense for the periods presented:~~

Three months ended September 30, Nine months ended September 30,
(in thousands) 2018 2017 2018 2017
Restricted stock award compensation $ 6,001
$ 5,422
$ 19,332
$ 16,856
Stock option award compensation 970
1,159
3,010
3,600
Performance share award compensation 3,689
4,255
12,431
12,063
Total stock-based compensation, gross 10,660
10,836
34,773
32,519
Less amounts capitalized in oil and natural gas properties (1,927 ) (1,870 ) (6,025 ) (5,642 )
Total stock-based compensation, net $ 8,733
$ 8,966
$ 28,748
$ 26,877

Note 8—7—Derivatives

Due to the inherent volatility in oil, NGL and natural gas prices ~~commodity transportation costs~~ and differences in the prices of oil, NGL and natural gas between where the Company produces and where the Company sells such commodities, the Company engages in derivative transactions, such as puts, swaps, collars and basis swaps ~~and, in the past, call spreads~~ to hedge price risk associated with a portion of the Company's anticipated production. By removing a portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from ~~operations due to fluctuations~~operations. See Notes 2.f and 9 in ~~commodity prices, commodity transportation costs~~the 2018 Annual Report for discussion of the Company's accounting policies for derivatives and ~~differences in commodity prices between where~~information on the transaction types and settlement indexes, respectively.

During the three months ended June 30, 2019, the Company ~~produces~~completed a hedge restructuring by early terminating puts and ~~where the Company sells its products.~~

~~Each put transaction has an established floor price.~~collars and entering into new swaps. The Company ~~pays its counterparty~~paid a ~~premium, which can be paid at inception or~~net termination amount of $5.4 million that included the full settlement of the deferred ~~until settlement, to enter into~~premiums associated with these early-terminated puts and collars. The present value of these deferred premiums, classified under Level 3 of the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the floor price multiplied by the hedged contract volume. When the settlement price is at or above the floor price in an individual monthfair value hierarchy, upon their early termination was $7.2 million. See Note 10 in the ~~contract period,~~2018 Annual Report for information about the ~~put option expires with no settlement for~~fair value hierarchy levels.

The following table details the derivatives that ~~particular month, except with regard to the deferred premium, if any.~~were terminated:

Each swap transaction has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.



	Aggregate volumes (Bbl)	Weighted-average floor price ($/Bbl)		Weighted-average ceiling price ($/Bbl)		Contract period
Oil puts	5,087,500	$	46.03	$	—	April 2019 - December 2019
Oil collars	1,134,600	$	45.00	$	76.13	January 2020 - December 2020

Each collar transaction has an established price floor and ceiling. Depending on the terms, the Company may pay its counterparty a premium, which can be paid at inception or deferred until settlement. When the settlement price is below the price floor established by these collars, the counterparty pays the Company an amount equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is between the price floor and price ceiling established by these collars in an individual month in the contract period, the collar expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any.

Each basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relationship to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the hedged contract volume.

Each call spread transaction has an established short call price and long call price. Depending on the terms, the counterparty may pay a premium to the Company to enter into the transaction. When the settlement price is above the short call price and less than or equal to the long call price, the Company pays its counterparty an amount equal to the difference between the settlement price and the short call price multiplied by the hedged contract volume. When the settlement price is above the long call price, the Company pays the counterparty an amount equal to the difference between the long call price and the short call price multiplied by the hedged contract volume. When the settlement price is at or below the short call price in an individual month in the contract period, the call option expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~Other than the oil basis swaps, the Company's oil~~The following table summarizes open derivative positions as of June 30, 2019, for derivatives ~~are settled based on the month's average daily NYMEX index price~~that were entered into through June 30, 2019, for the first nearby month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract. The oil basis swaps are settled based on either (i) the differential between the Argus Americas Crude West Texas Intermediate ("WTI") index prices for WTI Midland-weighted average for the trade month and WTI Cushing-WTI formula basis for the trade month as compared to the basis swaps' fixed differential price or (ii) the differential between the Argus Americas Crude WTI Houston-weighted average price for the trade month and the WTI Midland-weighted average price for the trade month as compared to the basis swaps' fixed differential price. The Company's NGL derivatives are settled based on the month's average daily OPIS index price for Mont Belvieu Purity Ethane, TET and Non-TET Propane, Non-TET Normal Butane, Non-TET Isobutane and Non-TET Natural Gasoline. Other than the natural gas basis swaps, the Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas WAHA for the calculation period. The natural gas basis swaps are settled based on the differential between the Inside FERC index price for West Texas WAHA for the calculation period and the NYMEX Henry Hub index price for the calculation period as compared to the basis swaps' fixed differential price.settlement periods presented:



	Remaining year 2019			Year 2020		Year 2021
Oil:
Puts:
Volume (Bbl)	644,000			366,000		—
Weighted-average floor price ($/Bbl)	$	55.00		$	45.00	$	—
Volume with deferred premium (Bbl)	644,000			—		—
Weighted-average deferred premium price ($/Bbl)	$	4.39		$	—	$	—
Swaps:
Volume (Bbl)	3,956,000			7,173,600		—
Weighted-average price ($/Bbl)	$	61.31		$	59.50	$	—
Collars:
Volume (Bbl)	—			—		912,500
Weighted-average floor price ($/Bbl)	$	—		$	—	$	45.00
Weighted-average ceiling price ($/Bbl)	$	—		$	—	$	71.00
Totals:
Total volume with floor price (Bbl)	4,600,000			7,539,600		912,500
Weighted-average floor price ($/Bbl)	$	60.42		$	58.79	$	45.00
Total volume with ceiling price (Bbl)	3,956,000			7,173,600		912,500
Weighted-average ceiling price ($/Bbl)	$	61.31		$	59.50	$	71.00
Basis Swaps:
WTI Midland to WTI NYMEX:
Volume (Bbl)	1,840,000			—		—
Weighted-average price ($/Bbl)	$	(2.89	)	$	—	$	—
WTI Midland to WTI formula basis:
Volume (Bbl)	552,000			—		—
Weighted-average price ($/Bbl)	$	(4.37	)	$	—	$	—
NGL:
Swaps - Purity Ethane:
Volume (Bbl)	1,196,000			366,000		912,500
Weighted-average price ($/Bbl)	$	14.22		$	13.60	$	12.01
Swaps - Non-TET Propane:
Volume (Bbl)	956,800			1,244,400		730,000
Weighted-average price ($/Bbl)	$	27.97		$	26.58	$	25.52
Swaps - Non-TET Normal Butane:
Volume (Bbl)	368,000			439,200		255,500
Weighted-average price ($/Bbl)	$	30.73		$	28.69	$	27.72
Swaps - Non-TET Isobutane:
Volume (Bbl)	92,000			109,800		67,525
Weighted-average price ($/Bbl)	$	31.08		$	29.99	$	28.79
Swaps - Non-TET Natural Gasoline:
Volume (Bbl)	312,800			402,600		237,250
Weighted-average price ($/Bbl)	$	45.80		$	45.15	$	44.31
Total NGL volume (Bbl)	2,925,600			2,562,000		2,202,775
Natural gas:
Henry Hub NYMEX Swaps:
Volume (MMBtu)	19,688,000			23,790,000		14,052,500
TABLE CONTINUES ON NEXT PAGE

During the nine months ended September 30, 2017, the Company completed a hedge restructuring by early terminating a swap that resulted in a termination amount to the Company of $4.2 million that was settled in full by applying the proceeds to pay the premium on one new collar entered into during the restructuring. The following details the derivative that was terminated:

Aggregate volumes
(Bbl)

Floor price
($/Bbl)

Ceiling price
($/Bbl)
Contract period
Oil swap 1,095,000
$ 52.12
$ 52.12
January 2018 - December 2018



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~The following table summarizes open positions as of September 30, 2018, and represents, as of such date, derivatives in place through December 2021 on annual production volumes:~~



	Remaining year 2019			Year 2020			Year 2021
Weighted-average price ($/MMBtu)	$	3.09		$	2.72		$	2.63
Basis Swaps:
Volume (MMBtu)	19,688,000			32,574,000			23,360,000
Weighted-average price ($/MMBtu)	$	(1.51	)	$	(0.76	)	$	(0.47	)

Remaining year 2018 Year
2019 Year
2020 Year
2021
Oil:

Puts:

Hedged volume (Bbl) 1,367,775
8,030,000
366,000
—
Weighted-average floor price ($/Bbl) $ 51.93
$ 47.45
$ 45.00
$ —
Swaps:

Hedged volume (Bbl) —
657,000
695,400
—
Weighted-average price ($/Bbl) $ —
$ 53.45
$ 52.18
$ —
Collars:

Hedged volume (Bbl) 1,030,400
—
1,134,600
912,500
Weighted-average floor price ($/Bbl) $ 41.43
$ —
$ 45.00
$ 45.00
Weighted-average ceiling price ($/Bbl) $ 60.00
$ —
$ 76.13
$ 71.00
Totals:
Total volume hedged with floor price (Bbl) 2,398,175
8,687,000
2,196,000
912,500
Weighted-average floor price ($/Bbl) $ 47.42
$ 47.91
$ 47.27
$ 45.00
Total volume hedged with ceiling price (Bbl) 1,030,400
657,000
1,830,000
912,500
Weighted-average ceiling price ($/Bbl) $ 60.00
$ 53.45
$ 67.03
$ 71.00
Basis Swaps:
WTI Midland to WTI Cushing:
Hedged volume (Bbl) 920,000
552,000
—
—
Weighted-average price ($/Bbl) $ (0.56 ) $ (4.37 ) $ —
$ —
WTI Houston to WTI Midland:
Hedged volume (Bbl) 920,000
1,810,000
—
—
Weighted-average price ($/Bbl) $ 7.30
$ 7.30
$ —
$ —
NGL:
Swaps - Purity Ethane:
Hedged volume (Bbl) 156,400
—
—
—
Weighted-average price ($/Bbl) $ 11.66
$ —
$ —
$ —
Swaps - Non-TET Propane:
Hedged volume (Bbl) 128,800
—
—
—
Weighted-average price ($/Bbl) $ 33.92
$ —
$ —
$ —
Swaps - Non-TET Normal Butane:
Hedged volume (Bbl) 46,000
—
—
—
Weighted-average price ($/Bbl) $ 38.22
$ —
$ —
$ —
Swaps - Non-TET Isobutane:
Hedged volume (Bbl) 18,400
—
—
—
Weighted-average price ($/Bbl) $ 38.33
$ —
$ —
$ —
Swaps - Non-TET Natural Gasoline:
Hedged volume (Bbl) 46,000
—
—
—
Weighted-average price ($/Bbl) $ 57.02
$ —
$ —
$ —
Total NGL volume hedged (Bbl) 395,600
—
—
—
TABLE CONTINUES ON NEXT PAGE



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

Remaining year 2018 Year
2019 Year
2020 Year
2021
Natural gas:

Puts:
Hedged volume (MMBtu) 2,055,000
—
—
—
Weighted-average floor price ($/MMBtu) $ 2.50
$ —
$ —
$ —
Collars:

Hedged volume (MMBtu) 3,928,400
—
—
—
Weighted-average floor price ($/MMBtu) $ 2.50
$ —
$ —
$ —
Weighted-average ceiling price ($/MMBtu) $ 3.35
$ —
$ —
$ —
Totals:
Total volume hedged with floor price (MMBtu) 5,983,400
—
—
—
Weighted-average floor price ($/MMBtu) $ 2.50
$ —
$ —
$ —
Total volume hedged with ceiling price (MMBtu) 3,928,400
—
—
—
Weighted-average ceiling price ($/MMBtu) $ 3.35
$ —
$ —
$ —
Basis Swaps:

Hedged volume (MMBtu) 2,300,000
20,075,000
25,254,000
—
Weighted-average price ($/MMBtu) $ (0.62 ) $ (1.05 ) $ (0.76 ) $ —

~~At each period end, the Company nets~~See Note 8.a for the fair value measurement of ~~derivatives by counterparty where the right of offset exists and reports this net basis on the "Derivatives" line items on the unaudited consolidated balance sheets as assets and/or liabilities. See~~ derivatives.

Note 9.a for a summary of the fair value of derivatives on a gross basis. The Company's derivatives were not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the "Gain (loss) on derivatives, net" line item. Gains and losses on derivatives are included in cash flows from operating activities.



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

~~Note 9—~~8—Fair value measurements

See Note 10 ~~"Fair value measurements"~~ in the ~~2017~~2018 Annual Report for discussion onof the Company's accounting policies for fair value measurements.

a. Fair value measurement on a recurring basis

The following tables summarize the Company's derivatives' fair value hierarchy by commodity and current and noncurrent assets and liabilities on a gross basis and the net presentation included in ~~the~~ "Derivatives" ~~line items~~ on the unaudited consolidated balance sheets as of the dates presented:


(in thousands)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets			Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of September 30, 2018:
As of June 30, 2019:
Assets:
Current:
Oil derivatives	$	—	$	10,390		$	—		$	10,390		$	(10,390	)	$	—		$	—	$	27,192		$	—		$	27,192		$	(9,821	)	$	17,371
NGL derivatives	—		—			—			—			—			—			—		17,134			—			17,134			(1,019		)	16,115
Natural gas derivatives	—		13,002			—			13,002			(9,309		)	3,693			—		26,229			—			26,229			(9,278		)	16,951
Oil derivative deferred premiums	—		—			—			—			—			—			—		—			—			—			(3,270		)	(3,270		)
Natural gas derivative deferred premiums	—		—			—			—			(619		)	(619		)
Noncurrent:
Oil derivatives	$	—	$	2,056		$	—		$	2,056		$	(2,056	)	$	—		$	—	$	18,217		$	—		$	18,217		$	(1,036	)	$	17,181
NGL derivatives	—		—			—			—			—			—			—		4,050			—			4,050			(566		)	3,484
Natural gas derivatives	—		474			—			474			(474		)	—			—		6,049			—			6,049			(916		)	5,133
Oil derivative deferred premiums	—		—			—			—			—			—
Natural gas derivative deferred premiums	—		—			—			—			—			—
Liabilities:
Current:
Oil derivatives	$	—	$	(41,692	)	$	—		$	(41,692	)	$	10,390		$	(31,302	)	$	—	$	(11,618	)	$	—		$	(11,618	)	$	9,821		$	(1,797	)
NGL derivatives	—		(4,807		)	—			(4,807		)	—			(4,807		)	—		(1,019		)	—			(1,019		)	1,019			—
Natural gas derivatives	—		233			—			233			9,309			9,542			—		(8,954		)	—			(8,954		)	9,278			324
Oil derivative deferred premiums	—		—			(17,265		)	(17,265		)	—			(17,265		)	—		—			(3,270		)	(3,270		)	3,270			—
Natural gas derivative deferred premiums	—		—			(847		)	(847		)	619			(228		)
Noncurrent:
Oil derivatives	$	—	$	(17,279	)	$	—		$	(17,279	)	$	2,056		$	(15,223	)	$	—	$	(1,036	)	$	—		$	(1,036	)	$	1,036		$	—
NGL derivatives	—		—			—			—			—			—			—		(566		)	—			(566		)	566			—
Natural gas derivatives	—		(2,468		)	—			(2,468		)	474			(1,994		)	—		(916		)	—			(916		)	916			—
Oil derivative deferred premiums	—		—			(3,728		)	(3,728		)	—			(3,728		)
Natural gas derivative deferred premiums	—		—			—			—			—			—
Net derivative liability positions	$	—	$	(40,091	)	$	(21,840	)	$	(61,931	)	$	—		$	(61,931	)
Net derivative asset (liability) positions																		$	—	$	74,762		$	(3,270	)	$	71,492		$	—		$	71,492



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)



(in thousands)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of December 31, 2018:
Assets:
Current:
Oil derivatives	$	—	$	44,425		$	—		$	44,425		$	(7,907	)	$	36,518
NGL derivatives	—		1,974			—			1,974			—			1,974
Natural gas derivatives	—		18,991			—			18,991			(3,267		)	15,724
Oil derivative deferred premiums	—		—			—			—			(14,381		)	(14,381		)
Noncurrent:
Oil derivatives	$	—	$	10,626		$	—		$	10,626		$	—		$	10,626
NGL derivatives	—		1,024			—			1,024			—			1,024
Natural gas derivatives	—		108			—			108			(728		)	(620		)
Liabilities:
Current:
Oil derivatives	$	—	$	(9,059	)	$	—		$	(9,059	)	$	7,907		$	(1,152	)
NGL derivatives	—		—			—			—			—			—
Natural gas derivatives	—		(7,290		)	—			(7,290		)	3,267			(4,023		)
Oil derivative deferred premiums	—		—			(16,565		)	(16,565		)	14,381			(2,184		)
Noncurrent:
Oil derivatives	$	—	$	—		$	—		$	—		$	—		$	—
NGL derivatives	—		—			—			—			—			—
Natural gas derivatives	—		(728		)	—			(728		)	728			—
Net derivative asset (liability) positions	$	—	$	60,071		$	(16,565	)	$	43,506		$	—		$	43,506

(in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the unaudited consolidated balance sheets
As of December 31, 2017:
Assets:
Current:
Oil derivatives $ —
$ 7,427
$ —
$ 7,427
$ (3,721 ) $ 3,706
NGL derivatives —
—
—
—
—
—
Natural gas derivatives —
10,546
—
10,546
(4,817 ) 5,729
Oil derivative deferred premiums —
—
—
—
(87 ) (87 )
Natural gas derivative deferred premiums —
—
—
—
(2,456 ) (2,456 )
Noncurrent:
Oil derivatives $ —
$ 11,613
$ —
$ 11,613
$ (6,087 ) $ 5,526
NGL derivatives —
—
—
—
—
—
Natural gas derivatives —
934
—
934
(934 ) —
Oil derivative deferred premiums —
—
—
—
(2,113 ) (2,113 )
Natural gas derivative deferred premiums —
—
—
—
—
—
Liabilities:
Current:
Oil derivatives $ —
$ (12,477 ) $ —
$ (12,477 ) $ 3,721
$ (8,756 )
NGL derivatives —
—
—
—
—
—
Natural gas derivatives —
—
—
—
4,817
4,817
Oil derivative deferred premiums —
—
(18,202 ) (18,202 ) 87
(18,115 )
Natural gas derivative deferred premiums —
—
(3,352 ) (3,352 ) 2,456
(896 )
Noncurrent:
Oil derivatives $ —
$ (2,389 ) $ —
$ (2,389 ) $ 6,087
$ 3,698
NGL derivatives —
—
—
—
—
—
Natural gas derivatives —
—
—
—
934
934
Oil derivative deferred premiums —
—
(7,129 ) (7,129 ) 2,113
(5,016 )
Natural gas derivative deferred premiums —
—
—
—
—
—
Net derivative asset (liability) positions $ —
$ 15,654
$ (28,683 ) $ (13,029 ) $ —
$ (13,029 )

Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index price(s), appropriate risk-adjusted discount rates and forward price curve models for substantially similar instruments generated from a compilation of data gathered from third parties.

The Company's deferred premiums associated with its derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (input rate), and then records the change in net present value to interest expense over the period from ~~the~~ trade ~~date~~ until the final settlement date at the end of the contract. After this initial valuation, the ~~net present value~~input rate of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the initial valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates. The deferred premiums are included in ~~the~~ "Derivatives" ~~line items~~ on the unaudited consolidated balance sheets, and as of ~~September~~June 30, ~~2018,~~2019, each of their input rates ~~range from 1.91% to 3.32% with a net fair value weighted-average rate~~is 2.31%.

The following table presents payments required for derivative deferred premiums as of ~~2.78%.~~June 30, 2019 for the periods presented:



(in thousands)	June 30, 2019
Remaining 2019	$	2,813
2020	477
Total	$	3,290



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~The following table presents payments required for derivative deferred premiums as of September 30, 2018 for the periods presented:~~

(in thousands) September 30, 2018
Remaining 2018 $ 5,405
2019 15,502
2020 1,295
Total $ 22,202

A summary of the changes in net assets and liabilities classified as Level 3 measurements for the periods presented are as follows:


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
(in thousands)	2018			2017			2018			2017			2019			2018			2019			2018
Balance of Level 3 at beginning of period	$	(25,026	)	$	(12,554	)	$	(28,683	)	$	(8,998	)	$	(12,644	)	$	(30,292	)	$	(16,565	)	$	(28,683	)
Change in net present value of derivative deferred premiums⁽¹⁾	(168		)	(88		)	(564		)	(199		)	(24		)	(185		)	(119		)	(396		)
Total purchases and settlements of derivative deferred premiums:
Purchases	(2,101		)	(15,996		)	(7,523		)	(22,994		)	—			—			—			(5,422		)
Settlements(2)	5,455			1,448			14,930			5,001			9,398			5,451			13,414			9,475
Balance of Level 3 at end of period	$	(21,840	)	$	(27,190	)	$	(21,840	)	$	(27,190	)	$	(3,270	)	$	(25,026	)	$	(3,270	)	$	(25,026	)

____________________________________________________________________________


(1)	These amounts are included in ~~the~~ "Interest expense" ~~line item~~ in the unaudited consolidated statements of operations.

~~b. Fair value measurement on a nonrecurring basis~~


(2)	The amounts for the three and six months ended June 30, 2019 include $7.2 million that represents the present value of deferred premiums settled upon their early termination.

See Note ~~10.b "Fair value measurement on a nonrecurring basis" and Note 4.c "2016 acquisitions of evaluated and unevaluated oil and natural gas properties"~~2.f in the ~~2017~~2018 Annual Report for discussion of the Company's accounting policies ~~and assumptions in estimating the fair values of assets acquired and liabilities assumed~~ for acquisitions of evaluated and unevaluated oil and natural gas properties. See Note 3.a for additional discussion of the Company's acquisitions of evaluated and unevaluated oil and natural gas properties for the nine months ended September 30, 2018.derivatives.

c.b. Items not accounted for at fair value

The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values.

The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented:


	September 30, 2018				December 31, 2017				June 30, 2019				December 31, 2018
(in thousands)	Long-term debt		Fair value⁽¹⁾		Long-term debt		Fair value⁽¹⁾		Long-term debt		Fair value⁽¹⁾		Long-term debt		Fair value⁽¹⁾
January 2022 Notes	$	450,000	$	448,875	$	450,000	$	454,500	$	450,000	$	420,750	$	450,000	$	402,885
March 2023 Notes	350,000		352,730		350,000		364,105		350,000		327,355		350,000		316,624
Senior Secured Credit Facility	170,000		170,084		—		—		235,000		235,004		190,000		190,054
Total	$	970,000	$	971,689	$	800,000	$	818,605	$	1,035,000	$	983,109	$	990,000	$	909,563

______________________________________________________________________________

(1)

The fair values of the debt outstanding on the January 2022 Notes and the March 2023 Notes were determined using the ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017~~2018 Level 1 fair value hierarchy quoted market price ~~(Level 1)~~ for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of ~~September~~June 30, 2019 and December 31, 2018 was estimated utilizing athe Level 2 fair value hierarchy pricing model for similar ~~instruments (Level 2).~~instruments. See Note 10 in the 2018 Annual Report for information about the fair value hierarchy levels.



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

Note ~~10—~~9—Net income per common share

Basic net income per common share is computed by dividing net income by the weighted-average ~~number of~~ common shares outstanding for the period. Diluted net income per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards, ~~and~~ non-vested performance share awards and the non-vested outperformance share award. See Note 6.c for additional discussion of these awards. The dilutive effects of these awards were calculated utilizing the treasury stock method. ~~See Note 7.c for additional discussion on these awards.~~



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table reflects the ~~calculation~~calculations of ~~basic and~~ diluted weighted-average common shares outstanding and basic and diluted net income per common share for the periods presented:


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
(in thousands, except for per share data)	2018		2017		2018		2017		2019		2018		2019		2018
Net income (numerator):
Net income—basic and diluted	$	55,050	$	11,027	$	175,022	$	140,413	$	173,382	$	33,452	$	163,891	$	119,972
Weighted-average common shares outstanding (denominator):
Basic⁽¹⁾	230,605		239,306		233,228		239,017		231,406		230,933		230,943		234,561
Non-vested restricted stock awards⁽²⁾	935		650		911		845
Outstanding stock option awards⁽³⁾	99		130		68		129
Non-vested performance share awards⁽⁴⁾	—		4,801		—		4,702
Dilutive non-vested restricted stock awards⁽²⁾									151		683		782		885
Dilutive outstanding stock option awards⁽³⁾									—		90		—		55
Diluted	231,639		244,887		234,207		244,693		231,557		231,706		231,725		235,501
Net income per common share:
Basic	$	0.24	$	0.05	$	0.75	$	0.59	$	0.75	$	0.14	$	0.71	$	0.51
Diluted	$	0.24	$	0.05	$	0.75	$	0.57	$	0.75	$	0.14	$	0.71	$	0.51

_____________________________________________________________________________


(1)	Weighted-average common shares outstanding used in the ~~computation~~calculation of basic and diluted net income per common share was computed taking into account share repurchases that occurred during the three and ~~nine~~six months ended ~~September~~June 30, 2018. See Note ~~7.a~~6.a for additional discussion of the Company's share repurchase program.

(2)

The effect of a significant portion of the non-vested restricted stock awards was excluded from the calculation of diluted net income per common share for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. The inclusion of these non-vested restricted stock awards would be anti-dilutive mainly due to the ~~sum of~~grant-date fair value per common share for the ~~assumed proceeds exceeding~~awards being greater than the average closing stock price during the period.

(3)

The effect of the outstanding stock option awards ~~with the exception of those granted in 2016,~~ was excluded from the calculation of diluted net income per common share for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average closing stock price during the period.

~~(4)~~

The effect of the non-vested performance share awards was excluded from the calculation of diluted net income per common share for the three and nine months ended September 30, 2018 as the awards were below the respective agreements' payout thresholds. The effect of the non-vested performance share awards granted in 2018 was calculated utilizing the following criteria defined in Note 7.c: (i) the RTSR Performance Percentage, (ii) the ATSR Appreciation and (iii) the ROACE Percentage from the beginning of the performance period to September 30, 2018 for each of the criteria to identify the RTSR Factor, the ATSR Factor and the ROACE Factor, respectively, which were used to compute the Performance Multiple to determine the number of shares for the dilutive effect. The effects of the non-vested performance share awards granted in 2016 and 2017 were calculated utilizing the Company's TSR from the beginning of each performance share awards' respective performance period to September 30, 2018 in comparison to the TSR of the peers specified in each respective performance share awards' agreement.

By assuming June 30, 2019 was the end of the respective performance periods of the non-vested performance share awards and the non-vested outperformance share award, the effects of these awards were excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2019, as the awards were below the respective agreements' payout thresholds, with the exception of the RTSR Performance Percentage-portion of the 2019 performance share awards, which was ultimately anti-dilutive due to the grant-date fair value per unit being greater than the average closing stock price during the periods. See Note 6.c for discussion of the performance and market criteria of these awards.

See Note 10 in the second-quarter 2018 Quarterly Report for discussion of the awards excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2018.

Note ~~11—~~10—Commitments and contingencies

a. Litigation

From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including proceedings for which the Company may not have insurance coverage. While many of these matters involve inherent uncertainty, ~~except with regard to the specific litigation noted below,~~ as of the date hereof, the Company does not currently



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

believe that any such legal proceedings will have a material adverse effect on the Company's business, financial position, results of operations or liquidity.

~~On May 3, 2017, Shell Trading (US) Company ("Shell") filed an Original Petition and Request for Disclosure in~~ During the ~~District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and Laredo effective October 1, 2016 through~~three months ended June 30, ~~2020 does not accurately reflect~~2019, the ~~compensation to be paid to Shell under certain circumstances due to~~Company finalized and received a ~~drafting mistake. Shell seeks reformation~~favorable settlement of ~~one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or,~~$42.5 million in the alternative, unilateral mistake, an award of the amounts Shell alleges it should have been or should be paid under the crude oil purchase agreement, court costs and attorneys' fees. The Company does not believe there was a drafting mistake made in the crude oil purchase agreement, which covered the sale to Shell of 19,000 barrels of crude oil per day ofconnection with the Company's ~~gross production as well as the purchase by the Company of like-quantity crude oil from Shell. On December 11, 2017, Shell filed its First Amended Petition,~~damage claims asserted in ~~which it asserted nine causes of action, including multiple new claims for breach of contract and fraud.~~

~~Effective May 1, 2018, Shell terminated the crude oil purchase agreement and ceased purchasing the Company's crude oil and selling crude oil~~a previously disclosed litigation matter relating to ~~the Company under the terms of such agreement. As~~ a result, the Company filed its Second Amended Answer and Original Counterclaim against Shell on June 15, 2018, in which the Company denies all allegations by Shell and seeks damages in excess of $150.0 million resulting from Shell's breach and wrongful termination of ~~the~~a crude oil purchase agreement. ~~Shell filed~~This settlement is included in "Litigation settlement" on the unaudited consolidated statements of operations. The Company does not anticipate the receipt of further payments in connection with this matter as this settlement constituted a ~~Second Amended Petition on June 1, 2018, in which it asserted a new cause of action against the Company for alleged repudiation of Shell's proposed reformed version~~full and final satisfaction of the ~~crude oil purchase agreement, a version never signed or agreed to by the Company.~~

Through April 30, 2018, the date on which Shell wrongfully terminated the crude oil purchase agreement, the Company had accounted for the costs and crude oil price realization as reflected in the terms of the crude oil purchase agreement. The accompanying unaudited consolidated balance sheets do not include any amounts for damage claims or attorneys' fees sought by Shell. As of September 30, 2018, the Company had estimated an aggregate amount of $37.4 million that is the subject of Shell's claims, which is generally based on the contractual amount in dispute under the pricing election that is the subject of Shell's claims applied to the barrels of crude oil purchased and sold through the date on which Shell wrongfully terminated the crude oil purchase agreement. As a result of such termination, the Company's estimate of this unrecorded amount is not anticipated to materially increase in the future. This estimate does not include damages sought by Shell pursuant to its latest repudiation claim asserted in its Second Amended Petition or amounts sought by Shell for recovery of attorneys' fees incurred for the prosecution of its claims.

The Company is unable to determine a probability of the outcome of this litigation at this time. The Company believes Shell's claims are meritless and the termination by Shell is improper and a breach of the crude oil purchase agreement. The Company therefore intends to vigorously defend itself against Shell's claims and pursue its rights under the terminated crude oil purchase agreement to seek all appropriate damages from Shell.

b. Drilling contracts

The Company has committed to ~~several~~ drilling rig contracts with third parties to facilitate the Company's drilling plans. Certain of these contracts are for ~~a term~~terms of multiple months and contain early termination clauses that require the Company to potentially pay penalties to the third party should the Company cease drilling efforts. These penalties would negatively impact the



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Company's financial statements upon early contract termination. There were no penalties incurred for early contract termination for either of the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 or ~~2017. The~~2018. As the Company's current drilling rig contracts are considered leases under the scope of ASC 842, the present value of the future commitment ~~of $22.9 million~~ as of ~~September~~June 30, ~~2018~~2019 related to drilling contracts with an initial term greater than 12 months is ~~not recorded~~included in "Operating lease liabilities" under "Current liabilities" on the ~~accompanying~~ unaudited consolidated balance ~~sheets.~~sheet as of June 30, 2019. See Note 3.a for further discussion of the impact of ASC 842 adoption. Management does not currently anticipate the early termination of these contracts in ~~2018.~~2019.

c. Firm sale and transportation commitments

The Company has committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. The Company incurred firm transportation payments on excess pipeline capacity and other contractual penalties of ~~$0.2~~$0.5 million and ~~$0.5~~$2.2 million during the three months ended ~~September~~June 30, ~~2018~~2019 and ~~2017,~~2018, respectively, and ~~$2.5~~$1.0 million and ~~$1.1~~$2.3 million during the ~~nine~~six months ended ~~September~~June 30, 2019 and 2018, ~~and 2017,~~ respectively. ~~For the three and nine months ended September 30, 2018, these~~These firm transportation payments on excess pipeline capacity and other contractual penalties are netted with the respective revenue stream in the unaudited consolidated statements of operations. ~~For the three and nine months ended~~



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

September 30, 2017, these firm transportation payments on excess pipeline capacity and other penalties are included in the "Other operating expenses" line item in the unaudited consolidated statements of operations. See Note 4.a for additional information regarding the presentation of firm transportation payments on excess pipeline capacity and other contractual penalties. Future commitments of ~~$367.7~~$341.5 million as of ~~September~~June 30, ~~2018~~2019 are not recorded in the ~~accompanying~~ unaudited consolidated balance sheets. ~~For information regarding the TA related to Medallion, see Note 3.c.~~

d. ~~Sand purchase and supply agreement~~

During the second quarter of 2018, the Company entered into a sand purchase and supply agreement, for a term of one year, whereby it has committed to buy a certain volume of in-basin sand, utilized in the Company's completion activities, for a fixed price. As of September 30, 2018, under the terms of this agreement, the Company is required to purchase a certain percentage of the volume commitment or it would incur a shortfall payment of $5.7 million at the end of the contract period.

e. Federal and state regulations

Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable federal and state regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations.

f.e. Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of ~~September~~June 30, ~~2018~~2019 or December 31, ~~2017.~~2018.

Note ~~12—~~11—Supplemental cash flow and non-cash information

The following table presents supplemental cash flow and non-cash information:



	Six months ended June 30,
(in thousands)	2019			2018
Supplemental cash flow information:
Capitalized interest	$	(420	)	$	(498	)
Cash received (paid) for income taxes⁽¹⁾	$	691		$	(1,136	)
Supplemental non-cash investing information:
Increase (decrease) in accrued capital expenditures	$	2,335		$	(8,878	)
Capitalized stock-based compensation in evaluated oil and natural gas properties	$	1,863		$	4,098
Capitalized asset retirement costs	$	356		$	577

______________________________________________________________________________


(1)	See Note 14 for additional discussion of the Company's income taxes.

Nine months ended September 30,
(in thousands) 2018 2017
Non-cash investing activities:
(Decrease) increase in accrued capital expenditures $ (44,533 ) $ 39,156
Capitalized stock-based compensation $ 6,025
$ 5,642
Capitalized asset retirement costs $ 719
$ 670
Other supplemental cash flow information:
Capitalized interest $ 710
$ 756



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents supplemental non-cash adjustments information related to leases:



(in thousands)	Six months ended June 30, 2019
Right-of-use assets obtained in exchange for operating lease liabilities⁽¹⁾	$	25,212

______________________________________________________________________________


(1)	See Note 3 for additional discussion of the Company's leases.

Note ~~13—~~12—Asset retirement obligations

See Note ~~2.m "Asset retirement obligations"~~2.k in the ~~2017~~2018 Annual Report for discussion onof the Company's accounting policies for asset retirement obligations.

The following table reconciles the Company's asset retirement obligation liability associated with tangible long-lived ~~assets:~~assets for the periods presented:



	Six months ended June 30,
(in thousands)	2019			2018
Liability at beginning of period	$	56,882		$	55,506
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	356			577
Accretion expense	2,072			2,227
Liabilities settled due to plugging and abandonment or removed due to sale	(1,362		)	(1,815		)
Liability at end of period	$	57,948		$	56,495

Note 13—Revenue recognition

a. Impact of ASC 606 adoption on the Medallion Sale

LMS has a Transportation Services Agreement (the "TA") with a wholly-owned subsidiary of Medallion under which LMS receives firm transportation of the Company's crude oil production from Reagan County and Glasscock County in Texas to Colorado City, Texas that continues to be in effect after the Medallion Sale. At December 31, 2017, the Medallion Sale was accounted for under the real estate guidance in ASC 360-20, Property, Plant, and Equipment ("ASC 360-20"), and the Company's maximum exposure to loss associated with future commitments under the TA was $141.1 million that was not recorded in the Company's unaudited consolidated balance sheets. Under ASC 360-20, as a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees. This deferred gain would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted ASC 606, Revenue from Contracts with Customers ("ASC 606") on January 1, 2018.

In adopting ASC 606, the guidance in ASC 360-20 was superseded by ASC 860, Transfers and Servicing ("ASC 860"). The Medallion Sale is within the scope of ASC 860 and qualifies for sale accounting and recognition of the previously deferred gain because as of the date of the Medallion Sale (i) the Company transferred and legally isolated its full interests in Medallion to GIP, (ii) GIP received the right to pledge or exchange Medallion ownership interests at its full discretion and (iii) the Company did not have effective control over Medallion. Therefore, the deferred gain of $141.1 million was recognized as an adjustment to the 2018 beginning balance of accumulated deficit, presented on the unaudited consolidated statements of stockholders' equity, in accordance with the modified retrospective approach of adoption. See Notes 4.c and 5.a in the 2018 Annual Report for further discussion of the Medallion Sale, the TA and the adoption of ASC 606.



Table of Contents	Laredo Petroleum, Inc.

Nine months ended September 30,
(in thousands) 2018 2017
Liability at beginning of period $ 55,506
$ 52,207
Liabilities added due to acquisitions, drilling, midstream service asset construction and other 719
492
Accretion expense 3,341
2,822
Liabilities settled due to plugging and abandonment or sale (2,246 ) (1,228 )
Revision of estimates —
178
Liability at end of period $ 57,320
$ 54,471
Condensed notes to the consolidated financial statements

(Unaudited)

b. Revenue recognition

Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated through fees for products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, natural gas lift and water delivery, recycling and takeaway and are recognized over time as the customer benefits from these services when provided. A more detailed summary of the underlying contracts that give rise to the Company's revenue and method of recognition can be found in Note 5.b in the 2018 Annual Report.

Note 14—Income taxes

The Company is subject to federal and state income taxes and the Texas franchise tax. The Company had federal net operating loss ~~carry-forwards~~carryforwards totaling ~~$1.8~~$1.9 billion and state of Oklahoma net operating loss ~~carry-forwards~~carryforwards totaling ~~$36.3~~$35.4 million as of ~~September~~June 30, ~~2018,~~2019, which begin expiring in 2026 and 2032, respectively. Due to the ~~passing~~enactment of Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"), ~~$86.4~~$180.7 million of the federal net operating loss ~~carry-forward~~carryforward will not expire but may be limited in future periods. As of ~~September~~June 30, ~~2018,~~2019, the Company believes it is more likely than not that a portion of the net operating loss ~~carry-forwards~~carryforwards are not fully realizable. The Company continues to consider new evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed. Such consideration includes projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of ~~September~~June 30, ~~2018,~~2019, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss ~~carry-forward~~carryforward from expiring unused and future projections of Oklahoma sourced income. As of ~~September~~June 30, ~~2018,~~2019, a ~~full~~total valuation allowance of ~~$298.8~~$202.1 million has been recorded against the ~~Company's federal and state of Oklahoma~~ net deferred tax ~~assets. As of September 30, 2018,~~asset, resulting in a net Texas deferred tax liability of ~~$1.8~~$6.7 million, which is included in "Other noncurrent liabilities" on the unaudited consolidated balance sheets.

The Company paid Alternative Minimum Tax ("AMT") related to the Medallion Sale in 2017. The payment of AMT creates an AMT credit carryforward. Due to changes in the Tax Act, AMT credit carryforwards do not expire and are now refundable over a five-year period. Therefore, as of June 30, 2019, a receivable has been recorded ~~along with~~in the ~~corresponding deferred income tax expense. Additionally, a current tax refund~~amount of ~~$0.4~~$4.1 million, of ~~Texas franchise tax~~which $3.1 million is ~~expected as a result of differences~~included in ~~estimated versus actual taxable income from the gain~~"Accounts receivable, net" and $1.0 million is included in "Other noncurrent assets, net" on the ~~Medallion Sale and is recorded as a current income tax benefit.~~unaudited consolidated balance sheets.

Note 15—Related party

Laredo's Chairman and Chief Executive Officer is on the board of directors of Helmerich & Payne, Inc. ("H&P"). The Company has drilling contracts with H&P that are long-term and short-term operating leases. The drilling contract, which is accounted for as a long-term operating lease under the scope of ASC 842 due to its initial term that was greater than 12 months, is capitalized and is included in "Operating lease right-of-use-assets" on the unaudited consolidated balance sheet. The present value of the future commitment is included in "Operating lease liabilities" under "Current liabilities" on the unaudited consolidated balance sheet. See Note 3 for additional discussion of the Company's adoption of ASC 842.

The following table presents the operating lease liability related to H&P included in the unaudited consolidated balance sheet:



(in thousands)	June 30, 2019
Operating lease liabilities	$	5,762

The following table presents the capital expenditures for oil and natural gas properties paid to H&P included in the unaudited consolidated statements of cash flows:



	Six months ended June 30,
(in thousands)	2019		2018
Capital expenditures for oil and natural gas properties	$	6,293	$	—



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 16—Subsidiary ~~guarantors~~Guarantors

The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility, ~~(and had guaranteed the May 2022 Notes until the May 2022 Notes Redemption Date),~~ subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the balance sheets, results of operations and cash flows of such subsidiaries as subsidiary ~~guarantors.~~Guarantors. The following unaudited condensed consolidating (i) balance sheets as of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017,~~2018, (ii) statements of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018 and (iii) statements of cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary ~~guarantors~~Guarantors on a stand-alone basis ~~(carrying any investment in subsidiaries under the equity method),~~ and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a condensed consolidated basis. Income taxes for LMS and for GCM are recorded on Laredo's balance sheets, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other.

Condensed consolidating balance sheet

June 30, 2019



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	66,348	$	10,262	$	—		$	76,610
Other current assets	114,653		1,252		—			115,905
Oil and natural gas properties, net	2,217,151		9,041		(26,024		)	2,200,168
Midstream service assets, net	—		131,633		—			131,633
Other fixed assets, net	37,910		23		—			37,933
Investment in subsidiaries	139,071		—		(139,071		)	—
Other noncurrent assets, net	54,172		3,501		—			57,673
Total assets	$	2,629,305	$	155,712	$	(165,095	)	$	2,619,922

Accounts payable and accrued liabilities	$	37,841	$	13,448	$	—		$	51,289
Other current liabilities	118,739		650		—			119,389
Long-term debt, net	1,029,526		—		—			1,029,526
Other noncurrent liabilities	72,854		2,543		—			75,397
Total stockholders' equity	1,370,345		139,071		(165,095		)	1,344,321
Total liabilities and stockholders' equity	$	2,629,305	$	155,712	$	(165,095	)	$	2,619,922



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating balance sheet

~~September~~December 31, 2018



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	83,424	$	10,897	$	—		$	94,321
Other current assets	97,045		1,386		—			98,431
Oil and natural gas properties, net	2,043,009		9,113		(22,551		)	2,029,571
Midstream service assets, net	—		130,245		—			130,245
Other fixed assets, net	39,751		68		—			39,819
Investment in subsidiaries	128,380		—		(128,380		)	—
Other noncurrent assets, net	23,783		4,135		—			27,918
Total assets	$	2,415,392	$	155,844	$	(150,931	)	$	2,420,305

Accounts payable and accrued liabilities	$	54,167	$	15,337	$	—		$	69,504
Other current liabilities	121,297		9,664		—			130,961
Long-term debt, net	983,636		—		—			983,636
Other noncurrent liabilities	59,511		2,463		—			61,974
Total stockholders' equity	1,196,781		128,380		(150,931		)	1,174,230
Total liabilities and stockholders' equity	$	2,415,392	$	155,844	$	(150,931	)	$	2,420,305

Condensed consolidating statement of operations

For the three months ended June 30, ~~2018~~2019

(in thousands) Laredo
Subsidiary
Guarantors
Intercompany
eliminations
Consolidated
company
Accounts receivable, net $ 103,109
$ 14,472
$ —
$ 117,581
Other current assets 70,413
1,533
—
71,946
Oil and natural gas properties, net 1,951,518
9,146
(22,174 ) 1,938,490
Midstream service assets, net —
132,415
—
132,415
Other fixed assets, net 42,071
193
—
42,264
Investment in subsidiaries 130,439
—
(130,439 ) —
Other noncurrent assets, net 13,113
3,965
—
17,078
Total assets $ 2,310,663
$ 161,724
$ (152,613 ) $ 2,319,774

Accounts payable and accrued liabilities $ 68,037
$ 18,600
$ —
$ 86,637
Other current liabilities 162,893
9,739
—
172,632
Long-term debt, net 963,191
—
—
963,191
Other noncurrent liabilities 79,256
2,946
—
82,202
Stockholders' equity 1,037,286
130,439
(152,613 ) 1,015,112
Total liabilities and stockholders' equity $ 2,310,663
$ 161,724
$ (152,613 ) $ 2,319,774



(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	184,037		$	49,251	$	(16,645	)	$	216,643
Total costs and expenses	127,310			46,175		(14,670		)	158,815
Operating income	56,727			3,076		(1,975		)	57,828
Interest expense	(15,765		)	—		—			(15,765		)
Other non-operating income, net	136,146			292		(3,368		)	133,070
Income before income taxes	177,108			3,368		(5,343		)	175,133
Total income tax expense	(1,751		)	—		—			(1,751		)
Net income	$	175,357		$	3,368	$	(5,343	)	$	173,382

Condensed consolidating ~~balance sheet~~statement of operations

~~December 31, 2017~~For the three months ended June 30, 2018



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total revenues	$	208,624		$	163,021		$	(20,599	)	$	351,046
Total costs and expenses	115,602			158,433			(17,756		)	256,279
Operating income	93,022			4,588			(2,843		)	94,767
Interest expense	(14,424		)	—			—			(14,424		)
Other non-operating expense, net	(42,303		)	(1,025		)	(3,563		)	(46,891		)
Income before income taxes	36,295			3,563			(6,406		)	33,452
Total income tax	—			—			—			—
Net income	$	36,295		$	3,563		$	(6,406	)	$	33,452

(in thousands) Laredo Subsidiary
Guarantors Intercompany
eliminations Consolidated
company
Accounts receivable, net $ 79,413
$ 21,232
$ —
$ 100,645
Other current assets 132,219
2,518
—
134,737
Oil and natural gas properties, net 1,596,834
9,220
(16,715 ) 1,589,339
Midstream service assets, net —
138,325
—
138,325
Other fixed assets, net 40,344
377
—
40,721
Investment in subsidiaries (7,566 ) —
7,566
—
Other noncurrent assets, net 15,526
3,996
—
19,522
Total assets $ 1,856,770
$ 175,668
$ (9,149 ) $ 2,023,289

Accounts payable and accrued liabilities $ 34,550
$ 23,791
$ —
$ 58,341
Other current liabilities 193,104
25,974
—
219,078
Long-term debt, net 791,855
—
—
791,855
Other noncurrent liabilities 54,967
133,469
—
188,436
Stockholders' equity 782,294
(7,566 ) (9,149 ) 765,579
Total liabilities and stockholders' equity $ 1,856,770
$ 175,668
$ (9,149 ) $ 2,023,289



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~Condensed consolidating statement of operations~~

~~For the three months ended September 30, 2018~~

(in thousands)
Laredo Subsidiary
Guarantors Intercompany
eliminations Consolidated
company
Total revenues
$ 225,970

$ 73,463

$ (19,687 )
$ 279,746
Total costs and expenses
123,942

69,146

(17,752 )
175,336
Operating income
102,028

4,317

(1,935 )
104,410
Interest expense
(14,845 )
—

—

(14,845 )
Other non-operating expense
(28,811 )
(26 )
(4,291 )
(33,128 )
Income before income taxes
58,372

4,291

(6,226 )
56,437
Income tax expense
(1,387 )
—

—

(1,387 )
Net income
$ 56,985

$ 4,291

$ (6,226 )
$ 55,050

~~Condensed consolidating statement of operations~~

~~For the three months ended September 30, 2017~~

(in thousands) Laredo Subsidiary
Guarantors Intercompany
eliminations Consolidated
company
Total revenues $ 157,902
$ 63,686
$ (15,770 ) $ 205,818
Total costs and expenses 97,686
62,245
(14,565 ) 145,366
Operating income 60,216
1,441
(1,205 ) 60,452
Interest expense (23,697 ) —
—
(23,697 )
Other non-operating income (expense) (24,287 ) 2,290
(3,731 ) (25,728 )
Income before income taxes 12,232
3,731
(4,936 ) 11,027
Income tax —
—
—
—
Net income $ 12,232
$ 3,731
$ (4,936 ) $ 11,027

Condensed consolidating statement of operations

For the ~~nine~~six months ended ~~September~~June 30, 2019



(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	357,558		$	103,583	$	(35,551	)	$	425,590
Total costs and expenses	247,045			98,398		(32,078		)	313,365
Operating income	110,513			5,185		(3,473		)	112,225
Interest expense	(31,312		)	—		—			(31,312		)
Other non-operating income, net	89,818			385		(5,570		)	84,633
Income before income taxes	169,019			5,570		(9,043		)	165,546
Total income tax expense	(1,655		)	—		—			(1,655		)
Net income	$	167,364		$	5,570	$	(9,043	)	$	163,891

Condensed consolidating statement of operations

For the six months ended June 30, 2018


(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total revenues	$	632,419		$	312,784		$	(54,715	)	$	890,488		$	406,449		$	239,321		$	(35,028	)	$	610,742
Total costs and expenses	345,232			302,143			(49,256		)	598,119			221,290			232,997			(31,504		)	422,783
Operating income	287,187			10,641			(5,459		)	292,369			185,159			6,324			(3,524		)	187,959
Interest expense	(42,787		)	—			—			(42,787		)	(27,942		)	—			—			(27,942		)
Other non-operating expense	(62,532		)	(1,307		)	(9,334		)	(73,173		)
Other non-operating expense, net													(33,721		)	(1,281		)	(5,043		)	(40,045		)
Income before income taxes	181,868			9,334			(14,793		)	176,409			123,496			5,043			(8,567		)	119,972
Income tax expense	(1,387		)	—			—			(1,387		)
Total income tax													—			—			—			—
Net income	$	180,481		$	9,334		$	(14,793	)	$	175,022		$	123,496		$	5,043		$	(8,567	)	$	119,972

Condensed consolidating statement of cash flows

For the six months ended June 30, 2019



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash provided by operating activities	$	266,522		$	317		$	(5,570	)	$	261,269
Capital expenditures and other, net	(298,227		)	(317		)	5,570			(292,974		)
Net cash provided by financing activities	42,354			—			—			42,354
Net increase in cash and cash equivalents	10,649			—			—			10,649
Cash and cash equivalents, beginning of period	45,150			1			—			45,151
Cash and cash equivalents, end of period	$	55,799		$	1		$	—		$	55,800

Condensed consolidating statement of cash flows

For the six months ended June 30, 2018



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash provided by operating activities	$	254,991		$	12,653		$	(5,043	)	$	262,601
Capital expenditures and other, net	(346,462		)	(12,653		)	5,043			(354,072		)
Net cash provided by financing activities	15,916			—			—			15,916
Net decrease in cash and cash equivalents	(75,555		)	—			—			(75,555		)
Cash and cash equivalents, beginning of period	112,158			1			—			112,159
Cash and cash equivalents, end of period	$	36,603		$	1		$	—		$	36,604



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~Condensed consolidating statement~~Note 17—Organizational restructuring

On April 2, 2019, the Company announced the retirement of ~~operations~~

~~For~~two of its Senior Officers. Additionally, on April 8, 2019 (the "Effective Date"), the ~~nine~~Company committed to a company-wide reorganization effort (the "Plan") that included a workforce reduction of approximately 20%, which included an Executive Officer. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Company's board of directors approved the Plan in response to recent market conditions and to reduce costs and better position the Company for the future. In connection with the retirements on April 2, 2019 and with the Plan, the Company incurred $10.4 million of one-time charges during the three months ended ~~September~~June 30, ~~2017~~

(in thousands) Laredo Subsidiary
Guarantors Intercompany
eliminations Consolidated
company
Total revenues $ 439,269
$ 190,926
$ (48,370 ) $ 581,825
Total costs and expenses 276,855
183,310
(42,179 ) 417,986
Operating income 162,414
7,616
(6,191 ) 163,839
Interest expense (69,590 ) —
—
(69,590 )
Other non-operating income 53,780
7,622
(15,238 ) 46,164
Income before income taxes 146,604
15,238
(21,429 ) 140,413
Income tax —
—
—
—
Net income $ 146,604
$ 15,238
$ (21,429 ) $ 140,413

~~Condensed consolidating statement~~2019 comprising of ~~cash flows~~

~~For~~compensation, taxes, professional fees, outplacement and insurance-related expenses. All stock-based compensation awards held by the ~~nine months ended September 30, 2018~~

(in thousands) Laredo Subsidiary
Guarantors Intercompany
eliminations Consolidated
company
Net cash provided by operating activities $ 402,065
$ 15,797
$ (9,334 ) $ 408,528
Change in investment between affiliates 3,115
(12,449 ) 9,334
—
Capital expenditures and other (533,083 ) (3,348 ) —
(536,431 )
Net cash provided by financing activities 66,151
—
—
66,151
Net decrease in cash and cash equivalents (61,752 ) —
—
(61,752 )
Cash and cash equivalents, beginning of period 112,158
1
—
112,159
Cash and cash equivalents, end of period $ 50,406
$ 1
$ —
$ 50,407

~~Condensed consolidating statement of cash flows~~

~~For~~two Senior Officers, the ~~nine months ended September 30, 2017~~

(in thousands) Laredo Subsidiary
Guarantors Intercompany
eliminations Consolidated
company
Net cash provided by operating activities $ 273,309
$ 13,980
$ (15,238 ) $ 272,051
Change in investment between affiliates (36,890 ) 21,652
15,238
—
Capital expenditures and other (321,261 ) (35,632 ) —
(356,893 )
Net cash provided by financing activities 72,988
—
—
72,988
Net decrease in cash and cash equivalents (11,854 ) —
—
(11,854 )
Cash and cash equivalents, beginning of period 32,671
1
—
32,672
Cash and cash equivalents, end of period $ 20,817
$ 1
$ —
$ 20,818
Executive Officer and the employees who were affected by the Plan were forfeited and the corresponding stock-based compensation totaling $6.1 million was reversed. See Note 6.c for additional information on the associated forfeiture activity.

Note ~~16—~~18—Subsequent events

On ~~October 15, 2018,~~July 31, 2019, the Company ~~borrowed~~paid $20.0 million on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was ~~$190.0~~$215.0 million as of ~~November 5, 2018.~~July 31, 2019.

On October 23, 2018, pursuant to the regular semi-annual redetermination, the lenders reaffirmed the borrowing base of $1.3 billion under the Senior Secured Credit Facility. The Company's aggregate elected commitment of $1.2 billion remains unchanged.

~~As of November 5, 2018, the Company had one letter of credit outstanding of $14.7 million under the Senior Secured Credit Facility.~~

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report as well as our audited consolidated financial statements and notes thereto included in our ~~2017~~2018 Annual Report. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please see "Cautionary Statement Regarding Forward-Looking Statements." Except for purposes of the unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report, references in this Quarterly Report to "Laredo,""we,""us,""our" or similar terms refer to Laredo, LMS and GCM collectively, unless the context otherwise indicates or requires. All amounts, dollars and percentages presented in this Quarterly Report are rounded and therefore approximate.

Executive overview

We are an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and midstream and marketing services, primarily in the Permian Basin of West Texas. Since our inception, we have grown primarily through our drilling program coupled with select strategic acquisitions and joint ventures.

Our financial and operating performance for the three months ended ~~September~~June 30, 2019 included the following:

Oil sales volumes of 2,771 MBbl, compared to 2,514 MBbl for the three months ended June 30, 2018, ~~included~~a 10% increase over the ~~following:~~comparative period;

Oil, NGL and natural gas sales of ~~$225.9~~$183.9 million, compared to ~~$157.6~~$208.6 million for the three months ended ~~September~~June 30, ~~2017;~~

~~Average daily~~2018, which is the result of a 28% decrease in average sales price per BOE and was partially offset by a 22% increase in MBOE volumes ~~of 71,382 BOE/D, compared to 60,011 BOE/D for the three months ended September 30, 2017;~~sold;

Net income of ~~$55.1~~$173.4 million, compared to ~~$11.0~~$33.5 million for the three months ended ~~September~~June 30, ~~2017;~~2018; and

Adjusted EBITDA (a non-GAAP financial measure) of ~~$160.6~~$153.2 million, compared to ~~$130.9~~$152.5 million for the three months ended ~~September~~June 30, ~~2017.~~2018. See page 4244 for a discussion and reconciliation of Adjusted EBITDA.

Our financial and operating performance for the ~~nine~~six months ended ~~September~~June 30, 2019 included the following:

Oil sales volumes of 5,305 MBbl, compared to 4,953 MBbl for the six months ended June 30, 2018, ~~included~~a 7% increase over the ~~following:~~comparative period;

Oil, NGL and natural gas sales of ~~$631.9~~$357.2 million, compared to ~~$438.1~~$406.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017;~~

~~Average daily~~2018, which is the result of a 27% decrease in average sales price per BOE and was partially offset by a 21% increase in MBOE volumes ~~of 67,330 BOE/D, compared to 57,044 BOE/D for the nine months ended September 30, 2017;~~sold;

Net income of ~~$175.0~~$163.9 million, compared to ~~$140.4~~$120.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017;~~2018; and

Adjusted EBITDA (a non-GAAP financial measure) of ~~$456.5~~$276.1 million, compared to ~~$352.6~~$295.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2018. See page 4244 for a discussion and reconciliation of Adjusted EBITDA.

Recent developments

Potential future low commodity price impact on our third-quarter 2019 full cost ceiling impairment test

Oil, NGL and natural gas prices have remained low in the third quarter of 2019. If prices remain at or below the current levels, subject to numerous factors and inherent limitations, some of which are discussed below, and all other factors remain constant, we will incur a non-cash full cost ceiling impairment in the third quarter of 2019, which will have an adverse effect on our results of operations.

There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. In addition to unknown future commodity prices, other uncertainties include (i) changes in drilling and completions costs, (ii) changes in oilfield service costs, (iii) production results, (iv) our ability, in a low price environment, to strategically drill the most economic locations in our multi-stack horizontal targets, (v) income tax impacts, (vi) potential recognition of additional proved undeveloped reserves, (vii) any potential value added to our proved reserves when testing recoverability from drilling unbooked locations, (viii) revisions to production curves based on additional data and (ix) the inherent significant volatility in the commodity prices for oil, NGL and natural gas.

Each of the above factors is evaluated on a quarterly basis and if there is a material change in any factor it is incorporated into our reserves estimation utilized in our quarterly accounting estimates. We use our reserve estimates to evaluate, also on a quarterly basis, the reasonableness of our resource development plans for our reported reserves. Changes in circumstance,

including commodity pricing, economic factors and the other uncertainties described above may lead to changes in our development plans.

Set forth below is a calculation of a potential future impairment of our evaluated oil and natural gas properties. Such implied impairment should not be interpreted to be indicative of our development plan or of our actual future results. Each of the uncertainties noted above has been evaluated for material known trends to be potentially included in the estimation of possible third-quarter effects. Based on such review, we determined that the impact of decreased commodity prices is the only significant known variable necessary in calculating the following scenario.

Our hypothetical third-quarter 2019 full cost ceiling calculation has been prepared by substituting (i) $53.01 per Bbl for oil, (ii) $14.86 per Bbl for NGL and (iii) $0.48 per Mcf for natural gas (collectively, the "Pro Forma Third-Quarter Prices") for the respective Realized Prices as of June 30, 2019. All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of low commodity prices on the third-quarter 2019 Realized Prices that will be utilized in our full cost ceiling calculation. The Pro Forma Third-Quarter Prices use a slightly modified Realized Price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for oil, NGL and natural gas for the 10 months ended July 1, 2019 and holding the July 26, 2019 prices constant for the remaining eleventh and twelfth months of the calculation. Based solely on the substitution of the Pro Forma Third-Quarter Prices into our June 30, 2019 reserve estimates, the implied third-quarter impairment would be $300 million. We believe that substituting these prices into our June 30, 2019 reserve estimates may help provide users with an understanding of the potential impact on our third-quarter 2019 full cost ceiling test.

See "Part I, Item 1A. Risk Factors—Risks related to our business—As a result of the volatility in prices for oil, NGL and natural gas, we have taken and may be required to take further write-downs of the carrying values of our properties" in our 2018 Annual Report.

Core area of operations

The oil and liquids-rich Permian Basin is characterized by multiple target horizons, long-lived reserves, high drilling success rates and high initial production rates. As of ~~September~~June 30, ~~2018,~~2019, we had assembled ~~120,465~~122,787 net acres in the Permian Basin.

Pricing and reserves

Our results of operations are heavily influenced by oil, NGL and natural gas prices. Oil, NGL and natural gas price fluctuations are caused by changes in global and regional supply and demand, market uncertainty, economic conditions, transportation constraints and a variety of additional factors. Historically, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may affect the economic viability of, and our ability to fund, our drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves.

During the second and third quarters of 2018, the Midland market crude oil price experienced an increased discount to WTI-Cushing prices, with the August 31, 2018 discount for prompt month delivery at $18 per Bbl of oil, primarily due to limited pipeline capacity constraining transportation of crude oil out of the Permian Basin to major marketing hubs including, but not limited to, Cushing, Oklahoma and the United States Gulf Coast. As of October 31, 2018, this Midland discount for prompt month delivery was $6 per Bbl of oil. This pipeline constraint is expected to continue to affect the Midland market oil price until further transportation capacity becomes operational or until basin-wide crude oil production decreases from its current levels. We will continue to pursue avenues to attempt to protect our oil value from basin differentials by securing transportation capacity, enabling us to sell oil in multiple markets, and entering into basis-swap derivatives.

We have entered into a number of derivative contracts that have enabled us to offset a portion of the changes in our cash flow caused by fluctuations in price and basis differentials for our sales of oil, NGL and natural gas, as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

The unweighted arithmetic average first-day-of-the-month prices for each month within the 12-month period prior to the end of the reporting period before pricing differentials, adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received when control passes to the purchaser/customer (the "Realized Prices"),Realized Prices utilized to value our reserves as of ~~September~~June 30, 2019 and June 30, 2018, ~~and September 30, 2017,~~ were ~~$58.83~~$55.69 per Bbl for oil, ~~$21.15~~$18.64 per Bbl for NGL and ~~$1.62~~$0.70 per Mcf for natural gas, and ~~$44.59~~$55.36 per Bbl for oil, ~~$16.55~~$19.15 per Bbl for NGL and ~~$2.16~~$1.80 per Mcf for natural gas, respectively. The Realized Prices used to estimate proved reserves do not include derivative transactions. ~~See "—Costs and expenses -~~ ~~Transportation and marketing expenses" for costs incurred prior to control passing to the final customer.~~ The unamortized cost of our evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of ~~September~~June 30, ~~2018~~2019 or ~~September~~June 30, ~~2017.~~2018. See Note 54 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our full cost method of accounting.

Horizontal drilling inof unconventional wells using enhanced completions techniques, including, but not limited to, hydraulic fracturing, is a relatively new process and, as such, forecasting the long-term production of such wells is inherently uncertain and subject to varying interpretations. As we receive and process geological and production data from these wells over time, we analyze such data to confirm whether previous assumptions regarding original forecasted production and reserves continue to appear accurate or require modification. While all production forecasts have elements of uncertainty over the life of the related wells, we are seeing indications that the oil portion of such reserves may be less than originally anticipated and the decline curves may be steeper than originally anticipated.

Initial production results, production decline rates, well density, completion design and operating method are examples of the numerous uncertainties and variables inherent in the estimation of proved reserves in future periods. The quantity of proved reserves is one of the many variables inherent in the calculation of depletion. Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on the affected properties, which decreases earnings and increases losses through higher depletion expense. We have experienced increased depletion per BOE sold for each of the last three quarters of 2018.

The table below presents our depletion expense for our evaluated oil and natural gas properties per BOE sold for the periods presented:

For the quarters ended
September 30, 2018 June 30, 2018 March 31, 2018
Depletion per BOE sold $ 7.94
$ 7.68
$ 7.34



	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
Depletion expense per BOE sold	$	8.27	$	7.68	$	8.51	$	7.52

Sources of our revenue

Our revenues are derived from the sale of produced oil, NGL and natural gas, the sale of purchased oil and providing midstream services to third parties, all within the continental United States and do not include the effects of derivatives. Our oil, NGL and natural gas revenues may vary significantly from period to period as a result of changes in volumes of production, pricing differentials and/or changes in commodity prices. Our sales of purchased oil revenue may vary due to changes in oil prices, pricing differentials and the amount of volumes purchased. Our midstream service revenues may vary due to oil throughput fees and the level of services provided to third parties for (i) oil and natural gas gathering and transportation systems and related facilities, (ii) natural gas lift, rig fuel and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure. See Notes 2.n and 5.b to our consolidated financial statements in our 2018 Annual Report for additional information regarding our revenue recognition policies.

The following table presents our sources of revenue as a percentage of total revenues:


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
	2018		2017		2018		2017		2019		2018		2019		2018
Oil sales	57	%	54	%	53	%	54	%	74	%	45	%	68	%	51	%
NGL sales	18	%	13	%	13	%	12	%	10	%	10	%	13	%	10	%
Natural gas sales	5	%	10	%	5	%	10	%	1	%	4	%	3	%	5	%
Midstream service revenues	1	%	1	%	1	%	1	%	1	%	1	%	1	%	1	%
Sales of purchased oil	19	%	22	%	28	%	23	%	14	%	40	%	15	%	33	%
Total	100	%	100	%	100	%	100	%	100	%	100	%	100	%	100	%

Results of operations

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 as compared to the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018

Oil, NGL and natural gas sales volumes, revenues and prices

The following table presents information regarding ~~produced~~our oil, NGL and natural gas sales volumes, revenues and average sales prices:


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
	2018			2017			2018			2017			2019			2018			2019			2018
Sales volumes:
Oil (MBbl)	2,651			2,425			7,604			7,027			2,771			2,514			5,305			4,953
NGL (MBbl)	1,987			1,491			5,328			4,187			2,200			1,778			4,299			3,341
Natural gas (MMcf)	11,577			9,630			32,697			26,154			15,092			10,947			27,941			21,120
Oil equivalents (MBOE)⁽¹⁾⁽²⁾	6,567			5,521			18,381			15,573			7,485			6,116			14,260			11,814
Average daily sales volumes (BOE/D)⁽²⁾	71,382			60,011			67,330			57,044			82,259			67,206			78,787			65,270
% Oil⁽²⁾	40		%	44		%	41		%	45		%	37		%	41		%	37		%	42		%
Sales revenues (in thousands):
Oil	$	160,007		$	110,194		$	469,972		$	313,875		$	160,030		$	159,051		$	289,201		$	309,965
NGL	50,814			27,700			115,979			68,329			22,197			36,805			54,432			65,165
Natural gas	15,043			19,664			45,908			55,927			1,636			12,705			13,606			30,865
Total oil, NGL and natural gas sales revenues	$	225,864		$	157,558		$	631,859		$	438,131		$	183,863		$	208,561		$	357,239		$	405,995
Average sales Realized Prices⁽²⁾:
Average sales prices⁽²⁾:
Oil, without derivatives ($/Bbl)⁽³⁾	$	60.36		$	45.44		$	61.80		$	44.67		$	57.76		$	63.26		$	54.52		$	62.58
NGL, without derivatives ($/Bbl)⁽³⁾	$	25.57		$	18.58		$	21.77		$	16.32		$	10.09		$	20.71		$	12.66		$	19.51
Natural gas, without derivatives ($/Mcf)⁽³⁾	$	1.30		$	2.04		$	1.40		$	2.14		$	0.11		$	1.16		$	0.49		$	1.46
Average price, without derivatives ($/BOE)⁽³⁾	$	34.39		$	28.54		$	34.38		$	28.13
Average sales price, without derivatives ($/BOE)⁽³⁾													$	24.56		$	34.10		$	25.05		$	34.37
Oil, with derivatives ($/Bbl)⁽⁴⁾	$	55.41		$	50.72		$	57.50		$	49.08		$	56.65		$	58.71		$	52.36		$	58.62
NGL, with derivatives ($/Bbl)⁽⁴⁾	$	23.99		$	17.98		$	20.95		$	15.90		$	12.82		$	20.07		$	14.04		$	19.15
Natural gas, with derivatives ($/Mcf)⁽⁴⁾	$	1.79		$	2.10		$	1.79		$	2.17		$	1.17		$	1.72		$	1.14		$	1.78
Average price, with derivatives ($/BOE)⁽⁴⁾	$	32.78		$	30.80		$	33.04		$	30.07
Average sales price, with derivatives ($/BOE)⁽⁴⁾													$	27.09		$	33.04		$	25.94		$	33.18

_____________________________________________________________________________



Delaware	45-3007926
~~Delaware~~ ~~(State~~(State or other jurisdiction of incorporation or organization)		~~45-3007926~~ ~~(I.R.S.~~(I.R.S. Employer Identification No.)



15 W. Sixth Street	Suite 900
Tulsa ~~Oklahoma~~	Oklahoma	74119
(Address of principal executive offices)			(Zip code)



Title of each class	Trading symbol	Name of each exchange on which registered
Common stock, $0.01 par value	LPI	New York Stock Exchange



Large accelerated filerý	☒	Accelerated filer o	☐

Non-accelerated filer o	☐	Smaller reporting company o	☐

Emerging growth companyo	☐



	Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	iii
Part I	1
Item 1. Consolidated Financial Statements (Unaudited)	1
Consolidated balance sheets as of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017~~2018	1
Consolidated statements of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018	2
Consolidated ~~statement~~statements of stockholders' equity for the ~~nine~~three and six months ended ~~September~~June 30, 2019 and 2018	3
Consolidated statements of cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018	4
Condensed notes to the consolidated financial statements:	5
Note 1—Organization and basis of presentation	5
Note 2—Recently issued or adopted accounting pronouncements	5
Note 3—~~Acquisitions and divestitures~~Leases	76
Note 4—~~Revenue recognition~~Property and equipment	89
Note 5—~~Property and equipment~~Debt	1110
Note 6—~~Debt~~Stockholders' equity and Equity Incentive Plan	12
Note 7—~~Stockholders' equity and stock-based compensation~~Derivatives	1418
Note 8—~~Derivatives~~Fair value measurements	1720
Note 9—~~Fair value measurements~~	21
~~Note 10—~~Net income per common share	22
Note 10—Commitments and contingencies	23
Note 11—Supplemental cash flow and non-cash information	24
Note ~~11—Commitments and contingencies~~12—Asset retirement obligations	2425
Note ~~12—Supplemental cash flow information~~13—Revenue recognition	25
Note 14—Income taxes	26
Note ~~13—Asset retirement obligations~~15—Related party	26
Note 16—Subsidiary Guarantors	27
Note ~~14—Income taxes~~	27
~~Note 15—Subsidiary guarantors~~	27
~~Note 16—Subsequent events~~17—Organizational restructuring	30
Note 18—Subsequent events	30
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3. Quantitative and Qualitative Disclosures About Market Risk	4546
Item 4. Controls and Procedures	47
~~Part II~~	48
~~Item 1. Legal Proceedings~~	48
~~Item 1A. Risk Factors~~	48
~~Item 2. Purchases of Equity Securities~~Part II	49
Item ~~3. Defaults Upon Senior Securities~~1. Legal Proceedings	49
Item ~~4. Mine Safety Disclosures~~1A. Risk Factors	49
Item ~~5. Other Information~~	49
~~Item 6. Exhibits~~2. Purchases of Equity Securities	50
~~SIGNATURES~~Item 3. Defaults Upon Senior Securities	50
Item 4. Mine Safety Disclosures	50
Item 5. Other Information	50
Item 6. Exhibits	51
SIGNATURES	52


	Common Stock					Additional paid-in capital				Treasury Stock (at cost)						Accumulated deficit								Common stock						Additional paid-in capital				Treasury stock (at cost)						Accumulated deficit
	Shares		Amount						Shares			Amount				Accumulated deficit			Total				Shares			Amount				Additional paid-in capital			Shares			Amount				Accumulated deficit			Total
Balance, December 31, 2017	242,521		$	2,425		Additional paid-in capital	$	2,432,262			—			$	—		$	(1,669,108	)		$	765,579
Adjustment to the beginning balance of accumulated deficit upon adoption of ASC 606 (see Note 4.a)	—		—			—				—			—			141,118				141,118
Balance, December 31, 2018																								233,936			$	2,339		$	2,375,286			—			$	—		$	(1,203,395	)		$	1,174,230
Restricted stock awards	3,248		33			(33		)		—			—			—				—				5,986			60			(60		)		—			—			—				—
Restricted stock forfeitures	(266	)	(3		)	3				—			—			—				—				(48	)		—			—				—			—			—				—
Share repurchases	—		—			—				11,049			(97,055		)	—				(97,055		)
Vested stock exchanged for tax withholding	—		—			—				517			(4,411		)	—				(4,411		)
Stock exchanged for tax withholding																								—			—			—				683			(2,612		)	—				(2,612		)
Stock exchanged for cost of exercise of stock options																								—			—			—				18			(76		)	—				(76		)
Retirement of treasury stock	(11,566	)	(115		)	(101,351		)		(11,566	)		101,466			—				—				(701	)		(7		)	(2,681		)		(701	)		2,688			—				—
Exercise of stock options	21		—			86				—			—			—				86				18			—			76				—			—			—				76
Stock-based compensation	—		—			34,773				—			—			—				34,773				—			—			9,305				—			—			—				9,305
Net loss																								—			—			—				—			—			(9,491		)		(9,491		)
Balance, March 31, 2019																								239,191			2,392			2,381,926				—			—			(1,212,886		)		1,171,432
Restricted stock awards																								1,064			11			(11		)		—			—			—				—
Restricted stock forfeitures																								(2,763	)		(28		)	28				—			—			—				—
Stock exchanged for tax withholding																								—			—			—				12			(34		)	—				(34		)
Retirement of treasury stock																								(12	)		—			(34		)		(12	)		34			—				—
Stock-based compensation (See Note 6.c)																								—			—			(459		)		—			—			—				(459		)
Net income	—		—			—				—			—			175,022				175,022				—			—			—				—			—			173,382				173,382
Balance, September 30, 2018	233,958		$	2,340		$	2,365,740			—			$	—		$	(1,352,968	)		$	1,015,112
Balance, June 30, 2019																								237,480			$	2,375		$	2,381,450			—			$	—		$	(1,039,504	)		$	1,344,321



(in thousands)	Three months ended June 30, 2019			Six months ended June 30, 2019
Operating lease costs⁽¹⁾	$	3,713		$	7,241
Short-term lease costs⁽²⁾	49,108			95,434
Variable lease costs⁽³⁾	1,254			1,772
Sublease income	(247		)	(494		)
Total lease costs	$	53,828		$	103,953

Supplemental cash paid for amounts included in the measurement of lease liabilities information⁽⁴⁾:
Operating cash flows from operating leases	$	1,294		$	2,824
Investing cash flows from operating leases⁽⁵⁾	$	2,270		$	4,516


(1)	Amounts represent straight-line costs associated with the Company's operating lease right-of-use assets.


(2)	Amounts represent costs associated with short-term leases that are not recorded on the unaudited consolidated balance sheets.


(3)	Variable lease costs are primarily comprised of the non-lease service component of drilling rig commitments above the minimum required payments. Both the minimum required payments and the non-lease service component of the drilling rig commitments are capitalized as additions to oil and natural gas properties.


(4)	Cash paid for amounts included in the measurement of lease liabilities may not agree to operating lease costs due to timing of cash payments and costs incurred.


(5)	Amounts associated with drilling operations are capitalized as additions to oil and natural gas properties.



	Three months ended September 30, 2018							Nine months ended September 30, 2018
(in thousands)	As computed under ASC 605		As reported under ASC 606		Increase/(decrease)			As computed under ASC 605		As reported under ASC 606		Increase/(decrease)
Revenues:
Oil sales	$	160,246	$	160,007	$	(239	)	$	472,496	$	469,972	$	(2,524	)
NGL sales	$	50,814	$	50,814	$	—		$	115,979	$	115,979	$	—
Natural gas sales	$	15,043	$	15,043	$	—		$	45,908	$	45,908	$	—
Costs and expenses:
Other operating expenses	$	1,353	$	1,114	$	(239	)	$	5,865	$	3,341	$	(2,524	)

Net income	$	55,050	$	55,050	$	—		$	175,022	$	175,022	$	—



	Aggregate volumes (Bbl)	Floor price ($/Bbl)		Ceiling price ($/Bbl)		Contract period
Oil swap	1,095,000	$	52.12	$	52.12	January 2018 - December 2018



	Remaining year 2018			Year 2019			Year 2020		Year 2021
Oil:
Puts:
Hedged volume (Bbl)	1,367,775			8,030,000			366,000		—
Weighted-average floor price ($/Bbl)	$	51.93		$	47.45		$	45.00	$	—
Swaps:
Hedged volume (Bbl)	—			657,000			695,400		—
Weighted-average price ($/Bbl)	$	—		$	53.45		$	52.18	$	—
Collars:
Hedged volume (Bbl)	1,030,400			—			1,134,600		912,500
Weighted-average floor price ($/Bbl)	$	41.43		$	—		$	45.00	$	45.00
Weighted-average ceiling price ($/Bbl)	$	60.00		$	—		$	76.13	$	71.00
Totals:
Total volume hedged with floor price (Bbl)	2,398,175			8,687,000			2,196,000		912,500
Weighted-average floor price ($/Bbl)	$	47.42		$	47.91		$	47.27	$	45.00
Total volume hedged with ceiling price (Bbl)	1,030,400			657,000			1,830,000		912,500
Weighted-average ceiling price ($/Bbl)	$	60.00		$	53.45		$	67.03	$	71.00
Basis Swaps:
WTI Midland to WTI Cushing:
Hedged volume (Bbl)	920,000			552,000			—		—
Weighted-average price ($/Bbl)	$	(0.56	)	$	(4.37	)	$	—	$	—
WTI Houston to WTI Midland:
Hedged volume (Bbl)	920,000			1,810,000			—		—
Weighted-average price ($/Bbl)	$	7.30		$	7.30		$	—	$	—
NGL:
Swaps - Purity Ethane:
Hedged volume (Bbl)	156,400			—			—		—
Weighted-average price ($/Bbl)	$	11.66		$	—		$	—	$	—
Swaps - Non-TET Propane:
Hedged volume (Bbl)	128,800			—			—		—
Weighted-average price ($/Bbl)	$	33.92		$	—		$	—	$	—
Swaps - Non-TET Normal Butane:
Hedged volume (Bbl)	46,000			—			—		—
Weighted-average price ($/Bbl)	$	38.22		$	—		$	—	$	—
Swaps - Non-TET Isobutane:
Hedged volume (Bbl)	18,400			—			—		—
Weighted-average price ($/Bbl)	$	38.33		$	—		$	—	$	—
Swaps - Non-TET Natural Gasoline:
Hedged volume (Bbl)	46,000			—			—		—
Weighted-average price ($/Bbl)	$	57.02		$	—		$	—	$	—
Total NGL volume hedged (Bbl)	395,600			—			—		—
TABLE CONTINUES ON NEXT PAGE



(in thousands)	September 30, 2018
Remaining 2018	$	5,405
2019	15,502
2020	1,295
Total	$	22,202



	For the quarters ended
	September 30, 2018		June 30, 2018		March 31, 2018
Depletion per BOE sold	$	7.94	$	7.68	$	7.34


(1)	BOE is calculated using a conversion rate of six Mcf per one Bbl.


(2)	The numbers presented are based on actual ~~results~~amounts and are not calculated using the rounded numbers presented in the table above.


(in thousands)	Oil		NGL		Natural gas			Total net effect of change		Oil			NGL			Natural gas			Total net effect of change
2017 Revenues	$	110,194	$	27,700	$	19,664		$	157,558
Effect of changes in average sales Realized Prices	39,565		13,895		(8,596		)	44,864
2018 Revenues										$	159,051		$	36,805		$	12,705		$	208,561
Effect of changes in average sales prices										(15,257		)	(23,358		)	(15,880		)	(54,495		)
Effect of changes in sales volumes	10,248		9,219		3,975			23,442		16,236			8,750			4,811			29,797
2018 Revenues	$	160,007	$	50,814	$	15,043		$	225,864
2019 Revenues										$	160,030		$	22,197		$	1,636		$	183,863


(1)	~~Average~~ For the three and six months ended June 30, 2019, non-cash stock-based compensation, net, excluding forfeitures related to our April 2019 organizational restructuring, was $5.6 million and $13.0 million, respectively, and on a per BOE sold basis was $0.75 and $0.91, respectively.


(2)	Selected average costs and expenses per BOE sold are based on actual amounts and are not calculated using the rounded numbers presented in the table above.



(in thousands)	Three months ended September 30, 2018 compared to 2017			Nine months ended September 30, 2018 compared to 2017
Increase (decrease) in fair value of derivatives outstanding	$	12,719		$	(62,370	)
Decrease in settlements received for matured derivatives, net	(17,523		)	(40,734		)
Decrease in settlements received for early terminations of derivatives, net	—			(4,234		)
Total change in gain (loss) on derivatives, net	$	(4,804	)	$	(107,338	)



(in thousands)	Three months ended June 30, 2019 compared to 2018			Six months ended June 30, 2019 compared to 2018
Change in mark-to-market gain (loss) on derivatives	$	116,480		$	56,767
Change in settlements received (paid) for matured derivatives, net	23,299			25,637
Change in settlements paid for early terminations of derivatives, net	(5,409		)	(5,409		)
Total change in gain (loss) on derivatives, net	$	134,370		$	76,995



(in millions, except for interest rates)	Principal		Interest rate
January 2022 Notes	$	450.0	5.625	%
March 2023 Notes	350.0		6.250	%
Total senior unsecured notes	$	800.0



($ in thousands, except % change)	June 30, 2019		December 31, 2018		change			% change
Senior Unsecured Notes⁽¹⁾	$	963,438	$	987,031	$	(23,593	)	(2	)%
Firm sale and transportation commitments⁽²⁾	341,477		365,940		(24,463		)	(7	)%
Senior Secured Credit Facility⁽³⁾	235,000		190,000		45,000			24	%
Asset retirement obligations⁽⁴⁾	57,948		56,882		1,066			2	%
Lease commitments⁽⁵⁾	26,052		34,374		(8,322		)	(24	)%
Derivative deferred premiums⁽⁶⁾	3,290		16,797		(13,507		)	(80	)%
Sand purchase and supply agreement⁽⁷⁾	—		3,858		(3,858		)	(100	)%
Total	$	1,627,205	$	1,654,882	$	(27,677	)	(2	)%


(4)	Amounts represent our asset retirement obligation liabilities. See Note 12 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our asset retirement obligations.


(7)	At June 30, 2019, we had met our commitment to purchase sand under this purchase and supply agreement.


•	is widely used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors;


•	helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and


•	is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting.


~~(1)~~	~~Proportionate Adjusted EBITDA of Medallion, our equity method investee until its sale on October 30, 2017, is calculated as follows:~~


(in thousands)	10% Increase		10% Decrease		10% Increase			10% Decrease
Net liability derivative position	$	70,691	$	54,814
Net (liability) asset derivative position					$	(18,140	)	$	161,923


	Maturity year						Maturity year
(in millions except for interest rates)	2022			2023⁽¹⁾			2022			2023⁽¹⁾
Senior Secured Credit Facility	$	—		$	170.0		$	—		$	235.0
Floating interest rate	—		%	3.438		%	—		%	3.688		%
January 2022 Notes	$	450.0		$	—		$	450.0		$	—
Fixed interest rate	5.625		%	—		%	5.625		%	—		%
March 2023 Notes	$	—		$	350.0		$	—		$	350.0
Fixed interest rate	—		%	6.250		%	—		%	6.250		%



Period	Total number of shares purchased⁽¹⁾	Weighted-average price paid per share		Total number of shares purchased as part of publicly announced plans⁽²⁾	Maximum value that may yet be purchased under the program as of the respective period-end date ⁽²⁾
July 1, 2018 - July 31, 2018	715	$	9.62	—	$	112,782,213
August 1, 2018 - August 31, 2018	—	$	—	—	$	112,782,213
September 1, 2018 - September 30, 2018	1,171,099	$	8.41	1,170,190	$	102,945,283
Total	1,171,814			1,170,190