0001661920-18-000038.txt : 20181107 0001661920-18-000038.hdr.sgml : 20181107 20181107060557 ACCESSION NUMBER: 0001661920-18-000038 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 68 CONFORMED PERIOD OF REPORT: 20180930 FILED AS OF DATE: 20181107 DATE AS OF CHANGE: 20181107 FILER: COMPANY DATA: COMPANY CONFORMED NAME: Lonestar Resources US Inc. CENTRAL INDEX KEY: 0001661920 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 810874035 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-37670 FILM NUMBER: 181164589 BUSINESS ADDRESS: STREET 1: 111 BOLAND STREET, SUITE 300 CITY: FORT WORTH STATE: TX ZIP: 76107 BUSINESS PHONE: 8175466403 MAIL ADDRESS: STREET 1: 111 BOLAND STREET, SUITE 300 CITY: FORT WORTH STATE: TX ZIP: 76107 10-Q 1 lone9301810q.htm 10-Q Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
 
FORM 10-Q
 
(Mark One)
QUARTERL Y REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2018
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from      to
Commission File Number: 001-37670
 
Lonestar Resources US Inc.
(Exact Name of Registrant as Specified in its Charter)
 
Delaware
 
81-0874035
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
111 Boland Street, Suite 301, Fort Worth, TX
 
76107
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code: (817) 921-1889
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes ý    No  ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
Accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Smaller reporting company
ý
 
 
 
Emerging growth company
ý
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ý
As of November 2, 2018, the registrant had 24,637,127 shares of Class A voting common stock, par value $0.001 per share, outstanding.

i



Table of Contents
 
 
Page
PART I.
 
Item 1.
 
 
 
 
 
Item 2.
Item 3.
Item 4.
PART II.
Item 1.
Item 1A.
Item 2.
Item 6.

ii



PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
 
September 30,
2018
 
December 31,
2017
Assets
Current assets
 
 
 
Cash and cash equivalents
$
4,542

 
$
2,538

Accounts receivable
 
 
 
Oil, natural gas liquid and natural gas sales
14,936

 
12,289

Joint interest owners and others, net
2,722

 
794

Related parties
184

 
162

Derivative financial instruments
28

 
472

Prepaid expenses and other
2,216

 
2,365

Total current assets
24,628

 
18,620

Property and equipment
 
 
 
Oil and gas properties, using the successful efforts method of accounting
 
 
 
Proved properties
895,983

 
750,226

Unproved properties
77,561

 
78,655

Other property and equipment
16,951

 
15,763

Less accumulated depreciation, depletion, amortization and impairment
(346,078
)
 
(274,374
)
Property and equipment, net
644,417

 
570,270

Deferred tax assets, net
2,376

 

Derivative financial instruments
288

 

Other non-current assets
1,554

 
2,918

Total assets
$
673,263

 
$
591,808

Liabilities and Stockholders' Equity
Current liabilities
 
 
 
Accounts payable
$
33,126

 
$
25,901

Accounts payable -- related parties
284

 
389

Oil, natural gas liquid and natural gas sales payable
13,705

 
8,747

Accrued liabilities
27,130

 
16,583

Derivative financial instruments
42,558

 
12,336

Total current liabilities
116,803

 
63,956

Long-term liabilities
 
 
 
Long-term debt
377,617

 
301,155

Asset retirement obligations
6,002

 
5,649

Deferred tax liabilities, net

 
4,769

Equity warrant liability
1,231

 
508

Equity warrant liability -- related parties
2,345

 
963

Derivative financial instruments
17,954

 
9,802

Other non-current liabilities
5,873

 
1,316

Total long-term liabilities
411,022

 
324,162

Commitments and contingencies (Note 12)


 


Stockholders' Equity
 
 
 
Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 24,637,127 and 24,506,647 issued and outstanding, respectively
142,655

 
142,655

Class B non-voting common stock, $0.001 par value, 5,000 shares authorized, 0 and 10,000 shares issued and outstanding, respectively

 

Series A-1 convertible participating preferred stock, $0.001 par value, 89,764 and 83,968 shares issued and outstanding, respectively

 

Additional paid-in capital
174,459

 
174,871

Accumulated deficit
(171,676
)
 
(113,836
)
Total stockholders' equity
145,438

 
203,690

Total liabilities and stockholders' equity
$
673,263

 
$
591,808

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

1



Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per share data)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
(Restated)
 
 
 
(Restated)
Revenues
 
 
 
 
 
 
 
Oil sales
$
47,846

 
$
23,162

 
$
120,705

 
$
52,742

Natural gas liquid sales
6,795

 
1,831

 
12,939

 
4,820

Natural gas sales
4,096

 
1,890

 
9,637

 
5,072

Total revenues
58,737

 
26,883

 
143,281

 
62,634

Expenses
 
 
 
 
 
 
 
Lease operating and gas gathering
6,687

 
4,576

 
17,761

 
11,053

Production and ad valorem taxes
3,218

 
1,541

 
8,145

 
3,656

Depreciation, depletion and amortization
23,775

 
16,530

 
59,937

 
42,003

Loss on sale of oil and gas properties

 
119

 
1,568

 
466

Impairment of oil and gas properties
12,169

 

 
12,169

 
27,081

General and administrative
4,661

 
2,644

 
13,385

 
8,925

Acquisition costs and other
315

 
333

 
302

 
3,001

Total expenses
50,825

 
25,743

 
113,267

 
96,185

Income (loss) from operations
7,912

 
1,140

 
30,014

 
(33,551
)
Other (expense) income
 
 
 
 
 
 
 
Interest expense
(10,215
)
 
(5,965
)
 
(28,771
)
 
(19,816
)
Unrealized (loss) gain on warrants
509

 
402

 
(2,105
)
 
3,286

(Loss) gain on derivative financial instruments
(18,198
)
 
(7,657
)
 
(54,852
)
 
6,505

Loss on extinguishment of debt

 

 
(8,619
)
 

Total other expense, net
(27,904
)
 
(13,220
)
 
(94,347
)
 
(10,025
)
Loss before income taxes
(19,992
)
 
(12,080
)
 
(64,333
)
 
(43,576
)
Income tax benefit
282

 
4,956

 
6,493

 
15,854

Net loss
(19,710
)
 
(7,124
)
 
(57,840
)
 
(27,722
)
Preferred stock dividends
(1,975
)
 
(1,824
)
 
(5,796
)
 
(2,120
)
Net loss attributable to common stockholders
$
(21,685
)
 
$
(8,948
)
 
$
(63,636
)
 
$
(29,842
)
 
 
 
 
 
 
 
 
Net loss per common share
 
 
 
 
 
 
 
Basic
$
(0.88
)
 
$
(0.41
)
 
$
(2.59
)
 
$
(1.37
)
Diluted
$
(0.88
)
 
$
(0.41
)
 
$
(2.59
)
 
$
(1.37
)
 
 
 
 
 
 
 
 
Weighted average common shares outstanding
 
 
 
 
 
 
 
Basic
24,599,744

 
21,822,015

 
24,598,816

 
21,822,015

Diluted
24,599,744

 
21,822,015

 
24,598,816

 
21,822,015

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

2



Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statement of Changes in Stockholders’ Equity
(In thousands, except share data)
 
Class A Voting
Common Stock
 
Series A-1
Preferred Stock
 
Additional
Paid-in
Capital
 
Accumulated
Deficit
 
Total
Stockholders'
Equity
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
Balance at December 31, 2017
24,506,647

 
$
142,655

 
83,968

 
$

 
$
174,871

 
$
(113,836
)
 
$
203,690

Payment-in-kind dividends

 

 
5,796

 

 

 

 

Issued pursuant to stock-based compensation plan
130,480

 

 

 

 
(601
)
 

 
(601
)
Retirement of Class B Common Stock

 

 

 

 
(10
)
 

 
(10
)
Stock-based compensation

 

 

 

 
199

 

 
199

Net loss

 

 

 

 

 
(57,840
)
 
(57,840
)
Balance at September 30, 2018
24,637,127

 
$
142,655

 
89,764

 
$

 
$
174,459

 
$
(171,676
)
 
$
145,438

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

3



Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
 
Nine Months Ended September 30,
 
2018
 
2017
 
 
 
(restated)
Cash flows from operating activities
 
 
 
Net loss
$
(57,840
)
 
$
(27,722
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
59,937

 
42,003

Stock-based compensation
3,637

 
985

Stock-based payments
(601
)
 

Deferred taxes
(7,145
)
 
(16,116
)
Loss (gain) on derivative financial instruments
54,852

 
(6,505
)
Settlements of derivative financial instruments
(16,323
)
 
4,894

Impairment of oil and natural gas properties
12,169

 
27,081

Loss on abandoned property and equipment
171

 

Non-cash interest expense
4,556

 
4,375

Unrealized loss (gain) on warrants
2,105

 
(3,286
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(4,596
)
 
(5,214
)
Prepaid expenses and other assets
(1,835
)
 
(3,559
)
Accounts payable and accrued expenses
6,733

 
11,531

Net cash provided by operating activities
55,820

 
28,467

 
 
 
 
Cash flows from investing activities
 
 
 
Acquisition of oil and gas properties
(4,762
)
 
(109,031
)
Development of oil and gas properties
(122,691
)
 
(56,918
)
Purchases of other property and equipment
(1,631
)
 
(11,580
)
Net cash used in investing activities
(129,084
)
 
(177,529
)
 
 
 
 
Cash flows from financing activities
 
 
 
Proceeds from borrowings and related party borrowings
348,744

 
102,988

Payments on borrowings and related party borrowings
(273,466
)
 
(27,507
)
Proceeds from the sale of preferred stock

 
77,800

Repurchase and retire Class B Common Stock
(10
)
 

Cost to issue equity

 
(2,790
)
Payments of debt issuance costs

 
(2,685
)
Net cash provided by financing activities
75,268

 
147,806

Net increase in cash and cash equivalents
2,004

 
(1,256
)
Cash and cash equivalents, beginning of the period
2,538

 
6,068

Cash and cash equivalents, end of the period
$
4,542

 
$
4,812

 
 
 
 
Supplemental information:
 
 
 
Cash paid for taxes
$
1,147

 
$
2,465

Cash paid for interest
22,324

 
11,060

Non-cash investing and financing activities:
 
 
 
Preferred stock issued for asset acquisition

 
10,795

Increase in asset retirement obligation
222

 
2,318

Increase in liabilities for capital expenditures
16,988

 
1,670

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

4



Lonestar Resources US Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Basis of Presentation
Organization and Nature of Operations
Lonestar Resources US Inc. (“Lonestar”) is an independent oil and natural gas company focused on the development, production and acquisition of unconventional oil, natural gas liquids (“NGLs”) and natural gas properties in the Eagle Ford shale play in South Texas, primarily through our subsidiary, Lonestar Resources, Inc. Lonestar is a Delaware corporation with our common stock listed and traded on the Nasdaq Global Select Market under the symbol “LONE”.
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Lonestar Resources US Inc., and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K/A for the year ended December 31, 2017 filed on November 2, 2018 (the “Form 10-K/A”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Lonestar,” refer to Lonestar Resources US Inc. and its subsidiaries.
The results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2018, our consolidated results of operations for the three and nine months ended September 30, 2018 and 2017, and our consolidated cash flows for the nine months ended September 30, 2018 and 2017.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net loss, current assets, current liabilities, total liabilities or stockholders’ equity.
Net Loss per Common Share
Basic net loss per common share is computed by dividing the net loss attributable to common stockholders by the weighted average number of common stock outstanding during the period. Diluted net loss per common share is calculated in the same manner but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of warrants, equity compensation awards and preferred equity shares under the as-converted method. Basic weighted average common shares exclude shares of non-vested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net loss per common share.
For the periods presented, there were no differences between the basic and diluted weighted average common shares. The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net loss per share, as their effect would have been antidilutive:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Preferred stock
 
14,635,078

 
13,337,174

 
14,317,760

 
5,324,860

Warrants
 
760,000

 
760,000

 
760,000

 
760,000

Stock appreciation rights
 
1,017,500

 
682,500

 
901,108

 
556,044

Restricted stock units
 
1,037,209

 
629,174

 
831,486

 
536,044


5



Impairment of Oil and Gas Properties
During the third quarter of 2018, the Company recorded an impairment charge of approximately $12.2 million relating to expiring leases in southern Brazos County included in unproved properties. During the second quarter of 2017, the Company recorded an impairment charge of approximately $27.1 million relating to its West Poplar property in Roosevelt County, Montana.
Recent Accounting Pronouncements
Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. Additional qualitative and quantitative disclosures will also be required. ASU 2016-02 is effective for the annual period beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted. Currently, entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management plans to adopt ASU 2016-02 in the quarter ending March 31, 2019. Changes to processes and internal controls to meet the standard’s reporting and disclosure requirements have been identified and are being implemented. In addition to lease agreements, service contracts and other agreements are also being reviewed to determine if they contain an embedded lease. At this time, we cannot estimate the amount that will be capitalized when this standard is adopted. The Company continues to evaluate the expected impact of this standard update on disclosures.
Revenue Recognition. Effective January 1, 2018, the Company adopted ASU 2014-09, using the modified retrospective method. Under the modified retrospective method, the Company recognized the cumulative effect of initially applying ASU 2014-09 as an adjustment to the opening balance of accumulated deficit; however, no significant adjustment was required as a result of adopting the new standard. Results for reporting periods beginning after January 1, 2018 are presented under ASC 606. The comparative information has not been restated and continues to be reported under historic accounting standards in effect for those periods. The impact of the adoption of ASU 2014-09 is expected to be immaterial to the Company’s net income on an ongoing basis. See Note 5. Revenue Recognition, for further discussion.

6



Note 2. Restatement of Previously Issued Financial Statements
As previously disclosed, we determined that instead of using updated oil and natural gas reserve estimates to calculate depreciation, depletion and amortization (“DD&A”) expense calculations looking back to the beginning of the applicable fiscal year, we instead should have used the updated oil and natural gas reserve estimates to calculate DD&A looking back to the beginning of the applicable current quarter. This methodology resulted in the understatement of DD&A expense and the overstatement of oil and gas properties, as well as the related income tax effects.
We concluded that the impact of applying the correct oil and natural gas reserve revision methodology to the DD&A calculation was materially different from our previously reported results under our historical practice. As a result, we are restating our consolidated financial statements for the three-month and nine-month periods ended September 30, 2017.
The table below sets forth the unaudited condensed consolidated statements of operations, including the balances originally reported, corrections and the as restated balances for each period:
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2017
In thousands
As Previously Reported
 
Correction
 
As Restated
 
As Previously Reported
 
Correction
 
As Restated
Depreciation, depletion and amortization
$
15,929

 
$
601

 
$
16,530

 
$
40,623

 
$
1,380

 
$
42,003

Total expenses
25,142

 
601

 
25,743

 
94,805

 
1,380

 
96,185

Income (loss) from operations
1,741

 
(601
)
 
1,140

 
(32,171
)
 
(1,380
)
 
(33,551
)
Loss before income taxes
(11,479
)
 
(601
)
 
(12,080
)
 
(42,196
)
 
(1,380
)
 
(43,576
)
Income tax benefit
4,718

 
238

 
4,956

 
15,339

 
515

 
15,854

Net loss
(6,761
)
 
(363
)
 
(7,124
)
 
(26,857
)
 
(865
)
 
(27,722
)
Net loss attributable to common stockholders
$
(8,585
)
 
$
(363
)
 
$
(8,948
)
 
$
(28,977
)
 
$
(865
)
 
$
(29,842
)
Net loss per common share
 
 
 
 

 
 
 
 
 

Basic
$
(0.39
)
 
$
(0.02
)
 
$
(0.41
)
 
$
(1.33
)
 
$
(0.04
)
 
$
(1.37
)
Diluted
$
(0.39
)
 
$
(0.02
)
 
$
(0.41
)
 
$
(1.33
)
 
$
(0.04
)
 
$
(1.37
)
The table below sets forth the unaudited condensed consolidated statement of cash flows and operating activities, including the balances originally reported, corrections and the as-restated balances for the restated period:
 
Nine Months Ended September 30, 2017
In thousands
As Previously Reported
 
Correction
 
As Restated
Cash flows from operating activities:
 
 
 
 
 
Net loss
$
(26,857
)
 
$
(865
)
 
$
(27,722
)
Depreciation, depletion and amortization
40,623

 
1,380

 
42,003

Deferred taxes
(15,601
)
 
(515
)
 
(16,116
)
None of the information contained in the Notes has been restated.
Note 3. Acquisitions and Divestitures
New Corporate Headquarters
On August 2, 2017, the Company closed on the purchase of an office building in Fort Worth, Texas, with an acquisition price approximating $10 million, to which the Company relocated its corporate operations in February 2018. In light of the relocation, the Company recorded an impairment charge of $1.6 million in Other Expense on the Unaudited Condensed Consolidated Statement of Operations during the first quarter of 2018, primarily reflecting the remaining future minimum rentals of the lease for the Company’s prior corporate office from the date of relocation to the end of the remaining lease term.

7



Battlecat Acquisition
On June 15, 2017, the Company closed an acquisition with Battlecat Oil & Gas, LLC (“Battlecat”) whereby the Company acquired oil and gas properties in the Eagle Ford Shale play in DeWitt, Gonzales and Karnes County, Texas (the “Battlecat Acquisition”). The total purchase consideration of approximately $59.8 million consisted of $55.0 million in cash and 1,184,632 shares of Series B Convertible Preferred Stock, par value $0.001 per share (“Series B Preferred Stock”) at a value of approximately $4.8 million. Allocation of the purchase consideration was as follows: $56.3 million to proved reserves; $2.9 million to unproved reserves and $0.6 million to unevaluated acreage and other assets. Additionally, the Company recorded an asset retirement obligation of approximately $0.2 million, resulting in fair value of net assets acquired of approximately $59.6 million. The Company accounted for the acquisition as a business combination under ASC 805. Acquisition-related costs of approximately $1.5 million were charged to Acquisition Costs in the Consolidated Statements of Operations.
Marquis Acquisition
On June 15, 2017, the Company closed an acquisition with SN Marquis LLC (a subsidiary of Sanchez Energy Corporation) (“Marquis”) whereby the Company acquired oil and gas properties in the Eagle Ford Shale play in Fayette, Gonzales and Lavaca County, Texas (the “Marquis Acquisition”). The total purchase consideration of approximately $50.0 million consisted of $44.0 million in cash and 1,500,000 shares of Series B Preferred Stock at a value of approximately $6.0 million. Allocation of the purchase price was as follows: $48.0 million to proved reserves; $0.6 to unproved reserves and $1.4 million to land, building and other assets. Additionally, the Company recorded an asset retirement obligation of approximately $1.9 million, resulting in fair value of net assets acquired of approximately $48.1 million. The Company accounted for the acquisition as a business combination under ASC 805. Acquisition-related costs of approximately $1.2 million were charged to Acquisition Costs in the Consolidated Statements of Operations.
Note 4. Commodity Price Risk Activities
The Company enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future oil, NGL and natural gas production and related cash flows. The oil, NGL and natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future oil, NGL and natural gas sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget.
Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from non-performance by the Company’s counterparty to a contract. The Company does not currently require cash collateral from any of its counterparties nor does its counterparties require cash collateral from the Company. At September 30, 2018, the Company had no open physical delivery obligations.
The following table summarizes the Company’s commodity derivative contracts as of September 30, 2018:
Commodity
 
Contract Type
 
Period
 
Volume Hedged
(Bbls/MMBtu per day)
 
Weighted Average Price
 
 
 
 
Swap
 
Floor
 
Ceiling
Oil -WTI
 
Swaps
 
October-December 2018
 
7,255

 
$
57.22

 

 

Oil -WTI
 
2-Way Collar
 
October-December 2018
 
500

 

 
$
50.00

 
$
59.45

Oil -WTI
 
Swaps
 
January-December 2019
 
5,930

 
53.94

 

 

Oil - Argus LLS
 
Basis Swaps
 
January-December 2019
 
5,430

 
5.00

 

 

Oil -WTI
 
Swaps
 
January-December 2020
 
2,680

 
56.97

 

 

Natural Gas - Henry Hub
 
Swaps
 
October-December 2018
 
4,548

 
3.06

 

 

During October 2018, the Company entered into additional Argus LLS basis swaps for 182,500 Bbls at a strike price of $5.55 per Bbl for the period of January through December 2019.

8



The Company has not designated any of the commodity derivatives as hedges under the applicable accounting standards. Consequently, all changes in fair value of these derivatives (realized and unrealized) are included in the Unaudited Condensed Consolidated Statements of Operations.
As of September 30, 2018, all of the Company’s economic derivative hedge positions were with large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contain credit-risk related contingent features.
Note 5. Revenue Recognition
Operating revenues are comprised of sales of crude oil, NGLs and natural gas.
In thousands
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Oil
 
$
47,846

 
$
23,162

 
$
120,705

 
$
52,742

NGLs
 
6,795

 
1,831

 
12,939

 
4,820

Natural gas
 
4,096

 
1,890

 
9,637

 
5,072

Total operating revenues
 
$
58,737

 
$
26,883

 
$
143,281

 
$
62,634

Accounting Policies
Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The Company recognizes revenue when control has been transferred to the customer, generally at the time commodities reach an agreed-upon delivery point. Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring products and is generally based upon a negotiated formula, list or fixed price. Typically, the Company sells its products directly to customers generally under agreements with payment terms typically less than 30 days.
Oil Revenues
The Company’s crude oil sales contracts are generally structured such that Lonestar commits and dedicates for sale a specified volume of oil production from agreed-upon leases to a purchaser. Oil is sold at a contractually-specified index price plus or minus a differential, and title and control of the product generally transfers at the delivery point specified in the contract, at which point related revenue is recognized. For those leases in which Lonestar operates with other working interest owners, the Company recognizes oil revenue proportionate to its entitled share of volumes sold. Currently, all of Lonestar’s oil production comes from the Eagle Ford play in South Texas, and direct sales to four purchasers account for the majority of its oil sales.
The Company’s oil purchase contracts are generally written to provide month-to-month terms with a 30-day cancellation notice. Sales of Lonestar’s oil production are typically invoiced monthly based on actual volumes measured at the agreed-upon delivery point and stated contract pricing for the month.
NGLs and Natural Gas Revenues
The Company’s NGL and natural gas purchase contracts are generally structured such that Lonestar commits and dedicates for sale a specified volume of NGL and/or natural gas production per day from agreed-upon leases to a purchaser. NGLs and natural gas are sold at a percentage of index prices of each component less any stated deductions. Control transfers at the delivery point specified in the contract, which typically is stated as the inlet or tailgate of a plant where the produced NGLs and natural gas are processed for subsequent transportation and consumption. In certain situations, Lonestar takes processed natural gas in-kind from a processing plant for sale under a separate purchase agreement with a different delivery point. The stated delivery point determines whether certain conditioning, treating, transportation and fractionation fees associated with the sold NGLs and natural gas are treated as operating expenses (occurring before the delivery point) or as deductions to revenues (occurring after the delivery point).
For those leases in which Lonestar operates with other working interest owners, the Company recognizes NGL and natural gas revenue proportionate to its entitled share of volumes sold. Currently, all of Lonestar’s NGL and natural gas

9



production comes from the Eagle Ford play in South Texas. Sales of Lonestar’s NGL and natural gas production is typically invoiced monthly based on actual volumes at the agreed-upon delivery point and stated contract pricing and allocations for the month.
Lonestar uses a third-party broker for its NGL and natural gas marketing. In this capacity, the third-party is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, submission of invoices and negotiation of contracts. In this agreement, Lonestar retains final approval of contracts and is not entitled to sales proceeds from the third-party until they are collected from the related purchasers. Commissions payable to the third-party broker for these services are treated as operating expenses in the financial statements.
Production Imbalances
Under ASC 606, revenue is recorded based on the Company’s share of volumes sold, regardless of whether the Company has taken its proportional share of volumes produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no imbalances at September 30, 2018.
Significant Judgements
As noted above, the Company engages in various types of transactions in which midstream entities process its gas and subsequently market resulting NGLs and residue gas to third-party customers on Lonestar’s behalf.  These types of transactions require judgement to determine whether Lonestar is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net.
The Company has determined that each unit of product represents a separate performance obligation under the terms of its purchase contracts, and therefore, future volumes are wholly unsatisfied. Therefore, the Company has utilized the practical expedient exempting a Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
Prior-Period Performance Obligations
The Company records revenue in the month production is delivered to the purchaser. Settlement statements for certain NGL and natural gas sales may not be received for 30 to 60 days after the date production is delivered, and as a result, Lonestar 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 its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Lonestar has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three and nine months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
Accounts Receivable and Other
Accounts receivable – Oil, natural gas liquid and natural gas sales on our Unaudited Condensed Consolidated Balance Sheets consist of amounts due from purchasers for commodity sales from our Eagle Ford fields. Payments from purchasers are typically due by the last day of the month following the month of delivery. There was no bad debt expense for any period presented, and an allowance for uncollectible accounts is unnecessary. The Company’s operations do not result in any contract assets or liabilities on the balance sheets.
Note 6. Fair Value Measurements
In accordance with ASC 820, Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. ASC 820 prioritizes the inputs used in measuring fair value into the following fair value hierarchy:

10



Level 1 – Quoted prices for identical assets or liabilities in active markets.
Level 2 – Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs derived principally from or corroborated by observable market data by correlation or other means.
Level 3 – Unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement falls in its entirety is determined based on the lowest level input that is significant to the measurement in its entirety.
Non-recurring fair value measurements include certain non-financial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and natural gas property assessments; warrants issued in equity offerings and the initial recognition of asset retirement obligations for which fair value is used. These estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these estimates as Level 3.
The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017, for each fair value hierarchy level:
 
 
Fair Value Measurements Using
In thousands
 
Quoted Prices in Active Markets
(Level 1)
 
Significant Other Observable Inputs
(Level 2)
 
Significant Unobservable Inputs
(Level 3)
 
Total
September 30, 2018 (unaudited)
 
 
Assets
 
 
 
 
 
 
 
 
Commodity derivatives
 
$

 
$
316

 
$

 
$
316

Liabilities:
 
 
 
 
 
 
 
 
Commodity derivatives
 
$

 
$
(60,512
)
 
$

 
$
(60,512
)
Warrant
 

 

 
(3,576
)
 
(3,576
)
Deferred compensation
 
(1,916
)
 

 
(1,837
)
 
(3,753
)
Total
 
$
(1,916
)
 
$
(60,196
)
 
$
(5,413
)
 
$
(67,525
)
 
 
 
 
 
 
 
 
 
December 31, 2017
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity derivatives
 
$

 
$
472

 
$

 
$
472

Liabilities:
 
 
 
 
 
 
 
 
Commodity derivatives
 
$

 
$
(22,138
)
 
$

 
$
(22,138
)
Warrant
 

 

 
(1,471
)
 
(1,471
)
Deferred compensation
 

 

 
(314
)
 
(314
)
Total
 
$

 
$
(21,666
)
 
$
(1,785
)
 
$
(23,451
)
Level 3 Gains and Losses
The table below sets forth a summary of changes in the fair value of the Company’s Level 3 liabilities for the nine months ended September 30, 2018:
In thousands
 
Warrant
 
Deferred Compensation
 
Total
Balance as of December 31, 2017
 
$
(1,471
)
 
$
(314
)
 
$
(1,785
)
Unrealized losses
 
(2,105
)
 
(1,523
)
 
(3,628
)
Balance as of September 30, 2018 (unaudited)
 
$
(3,576
)
 
$
(1,837
)
 
$
(5,413
)

11



The derivative asset and liability fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change because of changes in commodity prices, market conditions and other factors. The Company typically has numerous hedge positions that span several time periods and often result in both derivative assets and liabilities with the same counterparty, which positions are all offset to a single derivative asset or liability in the consolidated balance sheets, including the deferred premiums associated with its hedge positions. The Company nets the fair values of its derivative assets and liabilities associated with derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract.
The book values of cash and cash equivalents, receivables for oil, NGL and natural gas sales, joint interest billings, notes and other receivables, and accounts payable, approximate fair value due to the short-term nature of these instruments. The carrying value of debt approximates fair value since it is subject to a short-term floating interest rate that approximates the rate available to the Company, except for bonds, which are recorded at amortized cost less debt issuance costs. The fair value of the 11.25% Senior Notes (as defined in Note 8 below) approximates $250.0 million as of September 30, 2018, and the notes are considered a Level 3 liability, as they are based on market transactions that occur infrequently as well as internally generated inputs.
Note 7. Accrued Liabilities
Accrued liabilities consisted of the following as of the dates indicated:
In thousands
 
September 30,
2018
 
December 31,
2017
Bonus payable
 
$
2,060

 
$
2,250

Payroll payable
 
27

 
18

Accrued interest - 8.75% Senior Notes
 

 
2,768

Accrued interest -11.25% Senior Notes
 
7,031

 

Accrued interest - other
 
86

 
1,015

Accrued rent
 
210

 
156

Accrued well costs
 
13,353

 
8,386

Third party payments for joint interest expenditures
 
1,449

 

Accrued severance, property and franchise taxes
 
1,904

 
115

Accrued federal income tax
 
441

 
1,147

Other
 
569

 
728

Total accrued liabilities
 
$
27,130

 
$
16,583

Note 8. Long-Term Debt
The following long-term debt obligations were outstanding as of the dates indicated:
In thousands
 
September 30,
2018
 
December 31,
2017
Senior Secured Credit Facility
 
$
124,000

 
$
142,080

8.75% Senior Notes due 2019
 

 
151,848

11.25% Senior Notes due 2023
 
250,000

 

Mortgage debt
 
9,204

 
7,891

Other
 
270

 
759

Total long-term debt
 
383,474

 
302,578

Unamortized discount
 
(4,782
)
 
(949
)
Unamortized debt issuance costs
 
(1,075
)
 
(474
)
Total long-term debt net of debt issuance costs
 
$
377,617

 
$
301,155


12



Senior Secured Credit Facility
In July 2015, the Company, through its subsidiary Lonestar Resources America, Inc. ("LRAI"), entered into a $500 million Senior Secured Credit Facility with Citibank, N.A., as administrative agent, and other lenders party thereto (as amended, supplemented or modified from time to time, the “Credit Facility”), which has a maturity date of July 29, 2020. As of September 30, 2018, $124.0 million was borrowed under the Credit Facility, and the weighted average interest rate on borrowings under the Credit Facility was 6.35%. The Credit Facility may be used for loans and, subject to a $2.5 million sub-limit, letters of credit, and provides for a commitment fee of 0.375% to 0.5% based on the unused portion of the borrowing base under the Credit Facility.
The Company was in compliance with the terms of the Credit Facility as of September 30, 2018.
In January 2018, the Company entered into the Limited Waiver, Borrowing Base Redetermination Agreement, and Amendment No. 7 to the Credit Agreement, which included the following provisions:
maintained the borrowing base of $160 million until the next redetermination date;
waived the borrowing base redetermination that would otherwise have occurred in connection with the incurrence of the 11.25% Senior Notes (see below), and
amended certain other provisions of the Credit Facility.
As a result of the the May 2018 redetermination, the borrowing base was increased from $160 million to $190 million. The next scheduled redetermination date is November 2018.
Issuance of 11.25% Senior Notes
In January 2018, the Company issued $250.0 million of 11.250% senior notes due 2023 (the “11.25% Senior Notes”) to U.S.-based institutional investors. The net proceeds of $244.4 million were used to fully retire the 8.75% Senior Notes (as defined below), which included principal, interest and a prepayment premium of approximately $162.0 million. The remaining net proceeds were used to reduce borrowings under the Credit Facility.
The 11.25% Senior Notes mature on January 1, 2023, and bear interest at the rate of 11.25% per year, payable on January 1 and July 1 of each year, beginning July 1, 2018. At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the 11.25% Senior Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 111.25% of the principal amounts redeemed, plus accrued and unpaid interest, provided that at least 65% of the aggregate principal amount of 11.25% Senior Notes originally issued remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering.
At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem all or a part of the 11.25% Senior Notes at a redemption price equal to 100% of the principal amount redeemed, plus a “make-whole” premium as of, and accrued and unpaid interest.
On and after January 1, 2021, the Company may redeem the 11.25% Senior Notes, in whole or in part, plus accrued and unpaid interest, at the following redemption prices: 108.438% after January 1, 2021; 105.625% after January 1, 2022; and 100% after July 1, 2022.
The indenture contains certain restrictions on the Company’s ability to incur additional debt, pay dividends on the Company’s common stock, make investments, create liens on the Company’s assets, engage in transactions with affiliates, transfer or sell assets, consolidate or merger, or sell substantially all of the Company’s assets.
Retirement of 8.75% Senior Notes
Using proceeds from the issuance of the 11.25% Senior Notes, as discussed above, the Company fully retired the 8.750% Senior Unsecured Notes due April 15, 2019 (“the 8.75% Senior Notes”). Pursuant to the terms of the indenture, the 8.75% Senior Notes were redeemed at 104.375% of the outstanding principal amount, or approximately $158.5 million, which excluded accrued interest. In connection with this transaction, the Company recognized a $8.6 million loss on extinguishment during the first quarter of 2018.

13



Note 9. Stockholders’ Equity
Series A & B Preferred Stock
In June 2017, in connection with financing the Battlecat and Marquis Acquisitions, the Company issued 5,400 shares of Series A-1 Convertible Participating Preferred Stock, par value $0.001 per share (the “Series A-1 Preferred Stock”) and 74,600 shares of Series A-2 Convertible Participating Preferred Stock, par value $0.001 per share (the “Series A-2 Preferred Stock” and, together with the Series A-1 Preferred Stock, the “Series A Preferred Stock”), to Chambers Energy Capital (“Chambers”). Also in June 2017, in connection with the Battlecat and Marquis Acquisitions, the Company issued 1,184,632 and 1,500,000 shares of Series B Preferred Stock to Battlecat and Marquis, respectively (see Note 3, Acquisitions and Divestitures).
Pursuant to the terms of the Chambers agreement, the Company agreed to use commercially reasonable efforts to hold a stockholder meeting (the “Stockholder Meeting”) to obtain stockholder approval of the issuance of shares of the Company’s Class A voting common stock issuable upon conversion of all shares of Series A-1 Preferred Stock and Series A-2 Preferred Stock (upon their conversion to shares of Series A-1 Preferred Stock) issued or issuable pursuant to the agreement (the “Stockholder Approval”). The Stockholder Meeting was held on November 3, 2017, and Stockholder Approval was obtained. As a result of the Stockholder Approval, all outstanding Series A-2 Preferred Stock was converted to Series A-1 Preferred Stock. Also, on November 3, 2017, in accordance with the terms of the Series B Certificate of Designations, all of the outstanding shares of the Company’s Series B Preferred Stock were converted on a one-for-one basis into shares of the Company’s Class A voting common stock.
After the Chambers agreement closing, and for so long as the Approved Holders (as defined) beneficially own at least 10% of the total number of outstanding shares of Class A voting common stock and Class B non-voting common stock (collectively, “Common Stock”) of the Company, on an as-converted basis, or at least 15% of the number of Series A Preferred Stock issued to Chambers, the Company cannot undertake certain actions without the prior consent of holders of a majority of all shares of Common Stock, on an as-converted basis, held by the Approved Holders. Prior to June 15, 2020, Chambers and its affiliates are prohibited from directly or indirectly engaging in any short sales involving the Common Stock or securities convertible into, or exercisable or exchanged for, Common Stock. Without the prior written consent of the board, the Approved Holders are subject to customary standstill restrictions until the earlier of (i) the two-year anniversary of the date the Approved Holders are no longer entitled to designate any director to the Board and (ii) the date the Company fails to fully declare and pay all accrued dividends on either series of the Series A Preferred Stock after there are no PIK Quarters (as defined below) remaining. In connection with the closing and the issuance of shares of Series A Preferred Stock, the Company entered into a registration rights agreement with Chambers (the “Chambers RRA”). Under the Chambers RRA, the Company has agreed to provide to Chambers certain customary demand and piggyback registration rights relating to Chambers’ ownership of Company stock. The Chambers RRA contains customary terms and conditions, including certain customary indemnification obligations.
The Series A-1 Preferred Stock ranks senior to Class A voting common stock with respect to dividend rights and rights upon the liquidation, winding-up or dissolution of the Company, and the series initially has a stated value of $1,000 per share. Holders of Series A-1 Preferred Stock are entitled to vote with holders of Class A voting common stock on an as-converted basis. Shares of Series A-1 Preferred Stock are convertible into shares of Class A voting common stock at the option of the holders of such Series A-1 Preferred Stock at a per share rate (the “Conversion Rate”) equal to the Stated Value of such share divided by six, subject to certain adjustments (the “Conversion Price”). The Company has the option to convert Series A-1 Preferred Stock to Class A voting common stock if the volume weighted average price of Class A voting common stock exceeds the following percentages of the Conversion Price for twenty out of thirty consecutive trading days: (i) 200%, if such mandatory conversion occurs prior to June 15, 2019, (ii) 175%, if such mandatory conversion occurs after June 15, 2019 but before June 15, 2020, and (iii) 150%, if such mandatory conversion occurs after June 15, 2020.
Holders of Series A Preferred Stock are entitled to cumulative dividends payable quarterly initially at a rate of 9% per annum (the “Dividend Rate”) in cash and, for any 12 quarters (“PIK Quarters”), at the Company’s option, (i) in the form of additional shares of the respective series of Series A Preferred Stock at a per share price equal to $975 or (ii) by increasing Stated Value, in lieu of cash (collectively, the “PIK Option”). After the 12 PIK Quarters, if the Company fails to fully declare and pay dividends in cash, then the Dividend Rate for Series A Preferred Stock will automatically increase by 5.0% per annum for the next succeeding dividend period and then an additional 1.0% for each successive dividend period, up to a maximum Dividend Rate of 20.0% per annum, until the Company pays dividends at such increased rate fully in cash for two consecutive quarters. In addition to dividends rights described above, holders of the Series A Preferred Stock are entitled to receive dividends or distributions declared or paid on Class A voting common stock on an as-converted basis. If on June 15, 2024, the Prevailing Price is less than the Conversion Price then in effect, the Dividend Rate for Series A-1 Preferred Stock will automatically increase to 20.0% per annum, payable only in cash, unless automatically converted as described above. However, the Company, at its option, may instead elect to exchange each share of Series A-1 Preferred Stock for senior unsecured notes

14



of the Company with a two-year maturity, a 9.0% per annum coupon payable semi-annually in cash, and governed by terms substantially similar to the Company’s most recent high yield indenture at that time. After June 15, 2020, the Company may redeem shares of Series A Preferred Stock in cash at a per share amount equal to (i) 110% of the Stated Value, if the redemption occurs prior to June 15, 2021, (ii) 105% of the Stated Value, if the redemption occurs on or prior to June 15, 2022, and (iii) 100% of the Stated Value, if the redemption occurs after June 15, 2022, in each case, plus any unpaid dividends.
For the third and fourth quarters of 2017, the Company elected the PIK Option for the Class A Preferred Stock dividend payment, which resulted in the issuance of 1,991 additional shares of Series A-1 Preferred Stock and 1,977 additional shares of Series A-2 Preferred Stock, which were subsequently converted to shares of Series A-1 Preferred Stock during the fourth quarter of 2017.
For the first three quarters of 2018, the Company also elected the PIK Option for the Class A Preferred Stock dividend payment, which resulted in the issuance of 5,796 additional shares of Series A-1 Preferred Stock during the nine months ended September 30, 2018.
Common Stock Issuances
On November 3, 2017, as described above, the Company issued 2,684,632 shares of Class A voting common stock on a one-for-one basis in exchange for all of the of the Company’s outstanding Series B Preferred Stock.
Repurchase and Retirement of Class B Common Stock
In connection with the EF Realisation liquidation in October 2018 (see Note 13, Subsequent Events), the Company repurchased and retired 2,500 shares of the Class B non-voting common stock (the "Class B Stock") from Dr. Christopher Rowland at a cost of $10,000 on September 28, 2018. The Class B Stock was originally issued to Dr. Rowland in connection with the Company's reorganization in 2016. After the repurchase and retirement of the Class B Stock, there are no shares of Class B Stock issued and outstanding.
Note 10. Stock-Based Compensation
Restricted Stock Units
In February 2017, the Company granted awards of restricted stock units (“RSUs”) covering 612,000 shares to certain of its employees. In August 2017, 100,000 units were granted to the Company’s chairman of the board of directors, and in October 2017, 28,409 units were granted to the Company’s internal general counsel. In April and May 2018, 585,000 and 7,500 additional units were granted to certain of its employees, respectively.
The awards vest over a three-year period as follows: 40% on the first anniversary of issuance and 30% on each of the second and third anniversaries of issuance, such that the RSU’s will be fully vested on the third anniversary of issuance. The Company determined the fair value of granted RSUs based on the market price of the Class A voting common stock of the Company on the date of grant. RSUs are paid in Class A voting common stock or cash, at the Company’s option, after the vesting of the applicable RSU. Compensation expense for granted RSUs is recognized over the vesting period.
In February 2018, the Company elected to offer cash settlement to all employees for vested RSUs and, as a result of this modification, the RSU awards are classified as a liability on the Company’s balance sheet in accordance with ASC 718, Compensation – Stock Compensation, as of September 30, 2018. As of the date of the modification, periodic compensation expense related to the awards is recognized based on the fair value of the awards, subject to a floor valuation that represents the compensation expense amount that would have otherwise been recognized had the Company not modified the terms of the award. The modification of the RSU awards resulted in $0.2 million in incremental costs to the Company for the nine months ended September 30, 2018. The liability for RSUs on the Unaudited Condensed Consolidated Balance Sheet as of September 30, 2018 was $1.9 million and is included in other non-current liabilities.

15



The following table presents RSUs activity during the nine months ended September 30, 2018:
 
Shares
 
Weighted Average Remaining Contractual Term
(in years)
Non-vested RSUs at December 31, 2017
728,909

 
2.2

Granted
592,500

 
2.5

Vested
(284,200
)
 

Forfeited
(20,900
)
 

Non-vested RSUs at September 30, 2018
1,016,309

 
2.0

Stock Appreciation Rights
In February 2017, the Company granted awards of stock appreciation rights (“SARs”) covering 700,000 shares to certain of its employees and its non-employee directors. In April 2018, the Company granted additional awards of SARs covering 335,000 shares to certain of its employees and its non-employee directors.
The awards vest over a three-year period as follows: 40% on the first anniversary of issuance and 30% on each of the second and third anniversaries of issuance, such that the SAR’s will be fully vested on the third anniversary of issuance. The SARs will expire five-years after the date of issuance. The exercise price of the SAR is the fair market value of the Company’s Class A voting common stock on the date of the grant. The SAR entitles the holder to receive from the Company, upon exercise of the exercisable portion of the SAR, an amount determined by multiplying the excess of the fair market value of one share on the date of exercise over the exercise price per share by the number of shares with respect to which the SAR is exercised. SARs will be paid in cash or common stock at holder’s election once the SAR is vested, with the provision that the Company possesses sufficient liquidity to allow for cash settlement of the SAR. The SARs are accounted for as a liability on the Unaudited Condensed Consolidated Balance Sheets, which was approximately $1.8 million as of September 30, 2018, and are included in other non-current liabilities.
The following table presents SARs activity during the six months ended September 30, 2018:
 
Shares
 
Weighted Average Exercise Price Per Share
 
Weighted Average Remaining Contractual Term
(in years)
Outstanding at December 31, 2017
690,000

 
$
7.20

 
4.3

SARs vested and exercisable at December 31, 2017

 

 

Granted
335,000

 
4.46

 
4.5

Exercised

 

 

Expired/forfeited
(15,000
)
 

 

Outstanding at September 30, 2018
1,010,000

 
$
6.30

 
3.8

SARs vested and exercisable at September 30, 2018
280,000

 
$
7.20

 
3.4

Stock-Based Compensation Expense
For the three and nine months ended September 30, 2018, the Company recorded stock-based compensation expenses of approximately $924 thousand and $3.6 million, respectively, related to RSUs and SARs. As of September 30, 2018, the total unrecognized stock-based compensation cost to be recognized over the next three years is approximately $6.9 million.

16



Note 11. Related Party Activities
Leucadia
In August 2016, LRAI and the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau, as initial purchaser, Leucadia as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of (i) up to $49.9 million aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (“Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A voting common stock at a price equal to $5.00 per share (the “Warrants”). During 2016, LRAI issued $25.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 500,000 shares of its Class A voting common stock to Juneau. In December 2016, LRAI repaid to Juneau $21.0 million principal of the Second Lien Notes.
In connection with entering into the Purchase Agreement, the Company also entered into a registration rights agreement and an equity commitment agreement. Pursuant to the registration rights agreement, the Company had agreed to register for resale certain Class A voting common stock issued or issuable to Juneau and Leucadia, including those issuable upon exercise of the Warrants. The Form S-3 registration statement was filed with the Securities and Exchange Commission on November 7, 2017, and is effective. Leucadia agreed, pursuant to the equity commitment agreement, to purchase a certain number of Class A voting common stock in case the Company elected to pursue an equity offering prior to December 31, 2016. Pursuant to the equity commitment agreement, Leucadia purchased 3,478,261 shares of Class A voting common stock (costing $20 million) through a common stock offering, which closed in December 2016. In connection with Leucadia’s equity commitment, the Company paid Leucadia in January 2017 a $1.0 million fee, which was recorded as a reduction to additional paid-in capital. In the event Leucadia purchased not less than its commitment amount, the Company agreed to use commercially reasonable efforts to enter into arrangements to provide Leucadia with the right to appoint one director to the Board of the Company, provided that such right will terminate at such time as Leucadia and its affiliates own a number of shares of Class A voting common stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in such offering. Leucadia has elected to take an observer position on the board of directors, with no voting rights.
EF Realisation
In October 2016, the Company entered into a Board Representation Agreement (the “Board Representation Agreement”) with EF Realisation Company Limited (“EF Realisation”). Under the Board Representation Agreement, for as long as EF Realisation, together with its affiliates, beneficially owns 15% or more of the issued and outstanding shares of the Company’s Class A voting common stock, it has the right to nominate up to, but no more than, two directors to serve on the Board and for as long as EF Realisation, together with its affiliates, beneficially owns at least 10% but less than 15% of the Company’s issued and outstanding shares of Class A voting common stock, it has the right to nominate up to, but no more than, one director to serve on the Board.
On October 9, 2018, EF Realisation notified the Company that it had completed a voluntary liquidation and distribution of assets to certain of its shareholders, including the sale or distribution of all of EF Realisation's 4,174,259 shares of the Company's Class A Stock, representing approximately 17% of the Company's total Class A Stock outstanding at the time. Following the liquidation, EF Realisation is no longer a shareholder of the Company. See Note 13, Subsequent Events, for more information.
Amendment of Registration Rights Agreement
In connection with the Battlecat and Marquis acquisitions, in June 2017, the Company entered into (i) a first amendment to the registration rights agreement (the “Leucadia RRA Amendment”) with Leucadia and JETX Energy, LLC (f/k/a Juneau Energy, LLC), which amends the registration rights agreement by and among the same parties, and (ii) a first amendment to registration rights agreement (the “EF RRA Amendment” and, together with the Leucadia RRA Amendment, the “RRA Amendments”) with EF Realisation, which amends the registration rights agreement from October 2016 by and between the same parties. The RRA Amendments set forth the relative priorities, with respect to demand and piggyback registration rights, among each applicable party thereto, Battlecat, Marquis and Chambers under their respective registration rights agreements with the Company.

17



Other Related Party Transactions
New Tech Global Ventures, LLC, and New Tech Global Environmental, LLC, Companies in which Daniel R. Lockwood (a director of the Company) owns a limited partnership interest, has provided field engineering staff and consultancy services for the Company since 2013. The total cost for such services was approximately $641 thousand and $232 thousand for the three months ended September 30, 2018 and 2017, respectively, and $1.4 million and $742 thousand for the nine months ended September 30, 2018 and 2017, respectively.
Note 12. Commitments and Contingencies
In February 2018, the Company signed a rig under contract, the original term of which was completed during the second quarter of 2018, and has since been extended to provide for a drilling rate of $22.5 thousand per day with either party eligible to terminate the contract with 30 days' notice.
In March 2018, the Company signed a dedicated fleet contract that provides for hydraulic fracturing and wireline services at variable rates depending on the work performed. The early termination fee equals $133 thousand for each scheduled well that is not hydraulically fractured as of the date of termination. The contract expires on December 31, 2018. As of November 2018, the Company had completed the initial term of the contract and had extended the contract for two additional wells on the 2018 drilling schedule. The Company has the ability to further extend the contract on any additional wells added to the 2018 drilling schedule.
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other crude oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities. We are not aware of any pending or overtly threatened legal action against us that could have a material impact on our business.
Note 13. Subsequent Events

EF Realisation Liquidation
On October 9, 2018, EF Realisation notified the Company that it had completed a voluntary liquidation and distribution of assets to certain of its shareholders, including the sale or distribution of all of EF Realisation's 4,174,259 shares of the Company's Class A Stock, representing approximately 17% of the Company's total Class A Stock outstanding at the time. Following the liquidation, EF Realisation is no longer a shareholder of the Company.
Pursuant to the Board Representation Agreement by and between the Company and EF Realisation (the "Board Representation Agreement"), John H. Murray and Dr. Christopher Rowland (the "EF Realisation Directors") each submitted their resignations to the Company's Board of Directors on October 10, 2018 and October 9, 2018, respectively. Under the terms of the Board Representation Agreement, the EF Realisation Directors are required to submit each Board resignation when EF Realisation's ownership of Class A Stock falls below 15% and 10%, respectively, which occurred as a result of the EF Realisation liquidation noted above.
Also in connection with the EF Realisation liquidation, the Company repurchased and retired 2,500 shares of Class B Stock from Dr. Christopher Rowland at a cost of $10,000 on September 28, 2018 (see Note 9, Stockholders' Equity). The Class B Stock was originally issued to Dr. Rowland in connection with the Company's reorganization in 2016. After the repurchase and retirement of the Class B Stock, there are no shares of Class B Stock issued and outstanding.


18



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K/A for the year ended December 31, 2017 (the “Form 10-K/A”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K/A. Any terms used but not defined herein have the same meaning given to them in the Form 10-K/A. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of the Form 10-K/A, along with Forward Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
OVERVIEW
We are an independent oil and natural gas company, focused on the development, production and acquisition of unconventional oil, natural gas liquids (“NGLs”) and natural gas properties in the Eagle Ford shale play in South Texas, where we have accumulated approximately 82,154 gross (60,862 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of September 30, 2018. We operate in one industry segment, which is the exploration, development and production of oil, NGLs and natural gas. Our current operational activities and consolidated revenues are generated from markets exclusively in the United States, and, as of September 30, 2018, we had no long-lived assets located outside the United States.
Restatement of Previously Issued Financial Statements
As previously disclosed, we determined that instead of using updated oil and natural gas reserve estimates to calculate depreciation, depletion and amortization (“DD&A”) expense calculations looking back to the beginning of the applicable fiscal year, we instead should have used the updated oil and natural gas reserve estimates to calculate DD&A looking back to the beginning of the applicable current quarter. This methodology resulted in the understatement of DD&A expense and the overstatement of oil and gas properties, as well as the related income tax effects.
We concluded that the impact of applying the correct oil and natural gas reserve revision methodology to the DD&A calculation was materially different from our previously reported results under our historical practice. As a result, we are restating our consolidated financial statements for the periods impacted, and information within MD&A that was affected by the restatement has also been restated. See Note 2 to the Condensed Consolidated Financial Statements included in Item 1 for additional information and a reconciliation of the previously reported amounts to the restated amounts.
Third Quarter 2018 Operational Summary
During the third quarter of 2018, the Company reported production of 12,471 Boe/d. This is a 63% increase from the 7,662 Boe/d reported for the third quarter of 2017, consisting of approximately 58% crude oil, 23% NGLs and 19% natural gas. This production increase was driven by the drilling and completion of 8.0 gross / 6.8 net wells during the quarter. Additionally during the quarter, the Company entered into agreements to acquire approximately 3,000 acres at a total cost of $2.9 million. This acreage, which was strategically acquired in locations that are contiguous to Lonestar’s leasehold in Karnes and Gonzales Counties, increase the lengths of 42 of our drilling locations by an average of 42%. Year-to-date, Lonestar has acquired approximately 4,000 net acres in our core areas which we estimate add 8.2 MMBOE of net reserves and approximately $90 million of PV-10, organically replacing more than 200% of our 2018 annual production.

19



Recent Developments Regarding Lonestar Properties
Eagle Ford Shale Trend - Western Region
Asherton
In October 2018, the Company completed drilling operations on the Asherton #1HN and Asherton #3HN to total measured depths of 17,725 feet and 17,730 feet, respectively. The Asherton #1HN and #3HN wells were fracture-stimulated in engineered completions with an average proppant concentration of 1,985 pounds per foot over 37 stages and 36 stages, using diverters, respectively. On average, these wells were completed with a perforated interval of 10,788 feet and tested 1,053 Boe/d (three stream) on a 32/64’’ choke. The Asherton #1HN was completed with a perforated interval of 10,780 feet and tested 962 Bbls/d of oil and 1,202 Mcf/d of natural gas, or 1,237 Boe/d (three-stream) on a 32/64’’ choke. The Asherton #3HN, which immediately offsets wells that have produced for 4 years, was completed with a perforated interval of 10,795 feet and tested 673 Bbls/d of oil and 1,254 Mcf/d of natural gas, or 960 Boe/d (three-stream) on a 32/64’’ choke. Lonestar owns a 99% working interest (“WI”) and 75% Net Revenue Interest (“NRI”) in these two wells.
Beall Ranch
In Dimmit County, no new wells were completed during the three months ended September 30, 2018. The Beall Ranch leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018.
Burns Ranch Area
At the Burns Ranch leasehold in La Salle County, no new wells were completed during the three months ended September 30, 2018. Lonestar is currently mobilizing a drilling rig to Burns Ranch to drill three 10,000-foot laterals. These wells are expected to begin flowback operations in February 2019. Lonestar owns a 100% WI and 75% NRI in these wells.
Horned Frog
Lonestar drilled its first four wells utilizing its Geo-Engineered completion design during 2018. In June 2018, the Company began flowback operations on the Horned Frog NW #2H and Horned Frog NW #3H. These wells, which reached peak rate in July, have now been producing for in excess of four months and the results continue to be encouraging. Through the first 120 days, the Horned Frog NW #2H has produced a cumulative 58,000 barrels of oil and 253,000 Mcf of natural gas, or 118,000 barrels of oil equivalent on a three-stream basis, or an average of 983 Boe/d over its first 120 days of production. Over the same period, the Horned Frog NW #3H has produced a cumulative 56,000 barrels of oil and 241,000 Mcf of natural gas, or 113,000 barrels of oil equivalent on a three-stream basis, or an average of 944 Boe/d. The Horned Frog NW wells have continued to break away from forecast, outperforming third-party projections by 11%. Lonestar holds a 100% WI and 75% NRI in these wells and has an additional 5 drilling locations offsetting these wells.
 
Lonestar owns a 100% WI in the Horned Frog G #1H and Horned Frog H #1H, which were placed onstream in March 2018. These wells have now been producing for in excess of seven months and the results continue to outperform projections. During the first 210 days of production, the Horned Frog G #1H has produced cumulative production of 72,000 barrels of oil and 1,317,000 Mcf of natural gas, or 385,000 barrels of oil equivalent on a three-stream basis, an average of 1,832 Boe/d over its first 210 days of production. Over the same period, the Horned Frog H #1H has produced cumulative production of 67,000 barrels of oil and 1,230,000 Mcf of natural gas, or 359,000 barrels of oil equivalent on a three-stream basis, an average of 1,708 Boe/d over its first 210 days of production. Through their first seven months, these have outperformed third-party projections by 15%, the majority of which has been comprised of crude oil contribution.

20



Eagle Ford Shale Trend - Central Region
Cyclone
In July 2018, Lonestar completed the Cyclone DM #13H and Cyclone DM #14H to measured depths of 20,205 feet and 19,685 feet, respectively. As seismic indicated a potential fault, the Cyclone DM #13H well was steered higher within the Lower Eagle Ford shale, out of our target window for approximately 47% of the wells producing lateral. The Cyclone DM #13H has a perforated interval of 10,056 feet and produced at a Max 30-day production rate of 500 Boe/d, consisting of 443 barrels of oil per day, 26 barrels of natural gas liquids per day, and 186 Mcf per day of natural gas. The Cyclone DM #14H, drilled subsequently, was drilled lower in section in the Lower Eagle Ford in our target zone and has a perforated interval of 9,600 feet. The #14H produced at a Max 30-day production rate of 649 Boe/d, consisting of 578 barrels of oil per day, 32 barrels of natural gas liquids per day, and 233 Mcf per day of natural gas. Lonestar owns a 100% WI and 78.5% NRI in these wells.
Hawkeye
Lonestar owns an 87.5% WI in the Hawkeye #1H and Hawkeye #2H, which were placed onstream in January 2018. The Hawkeye wells have continued to deliver exceptional productivity, with oil production outperforming third-party projections by 24%. Now online in excess of nine months, the Hawkeye #1H has produced a cumulative 151,000 barrels of oil and 82,000 Mcf of natural gas, or 170,000 barrels of oil equivalent on a three-stream basis, or an average of 626 Boe/d over its first 270 days of production. Over the same period, the Hawkeye #2H has produced a cumulative 128,000 barrels of oil and 72,000 Mcf of natural gas, or 137,000 barrels of oil equivalent on a three-stream basis, or an average of 504 Boe/d.

In October 2018, the Company completed drilling operations on the Hawkeye #24H and Hawkeye #25H to total measured depths of 20,050 feet and 17,919 feet, respectively. These wells are projected to average approximately 10,200’ of perforated interval with an average proppant concentration of 1,500 pounds per foot. Fracture stimulation is set to begin in November and flowback operations are forecast to begin in December. Lonestar owns a 65% WI and 50% NRI in these wells.
Karnes County
During the third quarter of 2018, Lonestar drilled and completed 3.0 gross / 2.4 net wells in Karnes County. The Georg #24H, #25H & #26H were drilled to an average total measured depth of 15,480 feet and began flowback operations in August 2018. These wells were fracture-stimulated in engineered completions with an average proppant concentration of 1,980 pounds per foot over 20 stages per well and utilized diverters. The Georg #24H was completed with a perforated interval of 5,910 feet and produced at a Max 30-day production rate of 815 Boe/d, consisting of 708 barrels of oil per day, 57 barrels of natural gas liquids per day, and 300 Mcf/d of natural gas on a 26/64” choke. The Georg #25H was completed with a perforated interval of 6,115 feet and produced at a Max 30-day production rate of 837 Boe/d, consisting of 734 barrels of oil per day, 55 barrels of natural gas liquids per day, and 288 Mcf/d of natural gas on a 26/64” choke. The Georg #26H was completed with a perforated interval of 5,979 feet and produced at a Max 30-day production rate of 949 Boe/d, consisting of 825 barrels of oil per day, 66 barrels of natural gas liquids per day, and 348 Mcf/d of natural gas on a 26/64” choke. Lonestar owns an 80% WI and 61% NRI in these wells. Lonestar’s first Karnes County wells, which were completed in May, 2018 (the Georg EF #18H, #19H, and #20H) have now produced for four months. On average, these wells have produced a cumulative 78,000 barrels of oil and 64,000 Mcf of natural gas, or 92,900 barrels of oil equivalent on a three-stream basis.

21



Gonzales County
Lonestar drilled the Culpepper #3-2H, Culpepper #3-3H, and Culpepper #4-4H to an average total measured depth of 15,328 feet and began flowback operations in August 2018. These wells were fracture-stimulated in engineered completions with an average proppant concentration of 2,050 pounds per foot over 19 stages per well and utilized diverters. The Culpepper #3-2H was completed with a perforated interval of 5,337 feet and produced at a Max 30-day production rate of 689 Boe/d, consisting of 607 barrels of oil per day, 44 barrels of natural gas liquids per day, and 230 Mcf/d of natural gas on a 28/64” choke. The Culpepper #3-3H was completed with a perforated interval of 5,245 feet and produced at a Max 30-day production rate of 577 Boe/d, consisting of 508 barrels of oil per day, 37 barrels of natural gas liquids per day, and 193 Mcf/d of natural gas on a 28/64” choke. The Culpepper #3-4H was completed with a perforated interval of 5,383 feet and produced at a Max 30-day production rate of 640 Boe/d, consisting of 560 barrels of oil per day, 43 barrels of natural gas liquids per day, and 226 Mcf/d of natural gas on a 28/64” choke. Lonestar owns an 80% WI and 60% NRI in these wells.
Pirate
In Wilson County, no new wells were completed during the three months ended September 30, 2018. The Pirate leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018.
Eagle Ford Shale Trend - Eastern Region
Brazos & Robertson Counties
In Brazos County, no new wells were completed during the three months ended September 30, 2018. Lonestar is currently discussing drilling one well on our partners leasehold. Lonestar does not currently have drilling activity budgeted here in 2018.

22



RESULTS OF OPERATIONS
Certain of our operating results and statistics for the three and nine months ended September 30, 2018 and 2017 are summarized below:
In thousands, except per share and unit data
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
 
(Restated)
 
 
 
(Restated)
Operating revenues
 
 
 
 
 
 
 
 
Oil
 
$
47,846

 
$
23,162

 
$
120,705

 
$
52,742

NGLs
 
6,795

 
1,890

 
12,939

 
4,820

Natural gas
 
4,096

 
1,831

 
9,637

 
5,072

Total operating revenues
 
$
58,737

 
$
26,883

 
$
143,281

 
$
62,634

Total production volumes by product
 
 
 
 
 
 
 
 
Oil (Bbls)
 
660,836

 
483,000

 
1,758,393

 
1,099,098

NGLs (Bbls)
 
262,660

 
112,976

 
571,389

 
288,015

Natural gas (Mcf)
 
1,343,016

 
653,660

 
3,190,824

 
1,824,186

Total barrels of oil equivalent (BOE)
 
1,147,332

 
704,904

 
2,861,586

 
1,690,962

Daily production volumes by product
 
 
 
 
 
 
 
 
Oil (Bbls/d)
 
7,183

 
5,250

 
6,441

 
4,026

NGLs (Bbls/d)
 
2,855

 
1,228

 
2,093

 
1,055

Natural gas (Mcf/d)
 
14,600

 
7,105

 
11,689

 
6,682

Total barrels of oil equivalent (BOE/d)
 
12,471

 
7,662

 
10,482

 
6,194

Average realized prices
 
 
 
 
 
 
 
 
Oil ($ per Bbl)
 
$
72.40

 
$
47.96

 
$
68.65

 
$
47.99

NGLs ($ per Bbl)
 
25.87

 
16.19

 
22.64

 
16.74

Natural gas ($ per Mcf)
 
3.05

 
2.90

 
3.02

 
2.78

Total oil equivalent, excluding the effect from hedging ($ per BOE)
 
51.19

 
38.14

 
50.07

 
37.04

Total oil equivalent, including the effect from hedging ($ per BOE)
 
43.97

 
40.66

 
43.62

 
39.31

Operating and other expenses
 
 
 
 
 
 
 
 
Lease operating and gas gathering
 
$
6,687

 
$
4,576

 
$
17,761

 
$
11,053

Production and ad valorem taxes
 
3,218

 
1,541

 
8,145

 
3,656

Depreciation, depletion and amortization
 
23,775

 
16,530

 
59,937

 
42,003

General and administrative
 
4,661

 
2,644

 
13,385

 
8,925

Interest expense
 
10,215

 
5,965

 
28,771

 
19,816

Operating and other expenses per BOE
 
 
 
 
 
 
 
 
Lease operating and gas gathering
 
$
5.83

 
$
6.49

 
$
6.21

 
$
6.54

Production and ad valorem taxes
 
2.80

 
2.19

 
2.85

 
2.16

Depreciation, depletion and amortization
 
20.72

 
23.45

 
20.95

 
24.84

General and administrative
 
4.06

 
3.75

 
4.68

 
5.28

Interest expense
 
8.90

 
8.46

 
10.05

 
11.72


23



Production
The table below summarizes our production volumes for the three and nine months ended September 30, 2018 and 2017:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
Oil (Bbls/d)
7,183

 
5,250

 
37
%
 
6,441

 
4,026

 
60
%
NGLs (Bbls/d)
2,855

 
1,228

 
132
%
 
2,093

 
1,055

 
98
%
Natural gas (Mcf/d)
14,600

 
7,105

 
105
%
 
11,689

 
6,682

 
75
%
Total (BOE/d)
12,471

 
7,662

 
63
%
 
10,482

 
6,194

 
69
%
Total production during the third quarter of 2018 averaged 12,471 BOE per day, an increase of 63%, or 4,809 BOE per day, compared to the same period in 2017. Total production during first nine months of 2018 averaged 10,482 BOE per day, an increase of 69%, or 4,288 BOE per day, compared to the same period in 2017. These increases were primarily due to incremental production from the Battlecat and Marquis acquisitions that closed in June 2017 and strong well results from our recent development drilling in the Eagle Ford shale.
Oil, Natural Gas Liquid and Natural Gas Revenues
The table below summarizes our production revenues for the three and nine months ended September 30, 2018 and 2017:
In thousands
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
Oil
 
$
47,846

 
$
23,162

 
107
%
 
$
120,705

 
$
52,742

 
129
%
NGLs
 
6,795

 
1,831

 
271
%
 
12,939

 
4,820

 
168
%
Natural gas
 
4,096

 
1,890

 
117
%
 
9,637

 
5,072

 
90
%
Total operating revenues
 
$
58,737

 
$
26,883

 
118
%
 
143,281

 
$
62,634

 
129
%
Our oil, NGL and natural gas revenues during the three months ended September 30, 2018 increased $31.9 million, or 118%, compared to those revenues for the same period in 2017. For the nine months ended September 30, 2018, oil, NGL and natural gas revenues increased $80.6 million, or 129%, compared to those revenues for the same period in 2017. The changes in our oil, NGL and natural gas revenues are due to changes in production quantities and commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:
In thousands
 
Three months ended September 30, 2018 vs. 2017
 
Nine months ended September 30, 2018 vs. 2017
 
Increase in Revenues
 
Percentage Increase in Revenues
 
Increase in Revenues
 
Percentage Increase in Revenues
Change in oil, NGL and natural gas revenues due to:
 
 
 
 
 
 
 
 
Increase in production
 
$
25,140

 
79
%
 
$
56,837

 
70
%
Increase in commodity prices
 
6,714

 
21
%
 
23,810

 
30
%
Total increase in oil, NGL and natural gas revenues
 
$
31,854

 
100
%
 
$
80,647

 
100
%

24



Excluding the impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the three and nine months ended September 30, 2018 and 2017:
Average net realized price
Three Months Ended September 30,
 
Nine Months Ended September 30,
2018
 
2017
 
Change
 
2018
 
2017
 
Change
Oil ($/Bbl)
$
72.40

 
$
47.96

 
51
%
 
$
68.65

 
$
47.99

 
43
%
NGLs ($/Bbls)
25.87

 
16.19

 
60
%
 
22.64

 
16.74

 
35
%
Natural gas ($/Mcf)
3.05

 
2.90

 
5
%
 
3.02

 
2.78

 
9
%
Total ($/BOE)
51.19

 
38.14

 
34
%
 
50.07

 
37.04

 
35
%
Average NYMEX differentials
 
 
 
 


 
 
 
 
 


Oil per Bbl
$
2.90

 
$
(0.21
)
 
1,481
%
 
$
1.88

 
$
(1.43
)
 
231
%
Natural gas per Mcf
0.15

 
(0.03
)
 
600
%
 
0.08

 
(0.21
)
 
138
%
The average wellhead price for our production in the three months ended September 30, 2018 was $51.19 per BOE, a 34% increase compared to the average price in the comparable period in 2017. The average wellhead price for our production in the nine months ended September 30, 2018 was $50.07 per BOE, a 35% increase compared to the average price in the comparable period in 2017. Reported wellhead realizations were driven higher by significant increases in both the crude oil benchmark prices between the periods, as well as improvements in differentials to those benchmarks which we were successful in negotiating with our hydrocarbon purchasers, slightly decreased by a higher ratio of natural gas production in 2018, which typically carries a lower realized price than oil and NGLs on a per BOE basis.
Commodity Derivative Contracts
Our realized net loss on commodity derivative contracts was $8.3 million and $18.5 million for the three and nine months ended September 30, 2018, respectively, resulting from oil prices that were above the strike prices of our oil swap contracts. We realized gains of $1.8 and $3.8 million for the three and nine months ended September 30, 2017, resulting from oil and natural gas prices that were below our oil and natural gas swap contracts. We realized an average loss of $7.22 per BOE and $6.45 per BOE on our oil and natural gas swaps and 2-way oil collar contracts during the three and nine months ended September 30, 2018, respectively, as compared to an average gain of $3.21 per BOE and $2.08 per BOE for the three and nine months ended September 30, 2017, respectively. Our oil volumes hedged for the three months ended September 30, 2018 were 31% higher as compared to the three months ended September 30, 2017.
Production Expenses
The table below presents detail of production expenses and general and administrative ("G&A") expenses for the three and nine months ended September 30, 2018 and 2017:
In thousands, except expense per BOE
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
 
 
 
 
(restated)
 
 
 
 
 
(restated)
 
 
Production expenses
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating and gas gathering
 
$
6,687

 
$
4,576

 
46
 %
 
$
17,761

 
$
11,053

 
61
 %
Production and ad valorem taxes
 
3,218

 
1,541

 
109
 %
 
8,145

 
3,656

 
123
 %
Depreciation, depletion and amortization
 
23,775

 
16,530

 
44
 %
 
59,937

 
42,003

 
43
 %
General and administrative
 
4,661

 
2,644

 
76
 %
 
13,385

 
8,925

 
50
 %
Production expenses per BOE
 
 
 
 
 


 
 
 
 
 


Lease operating and gas gathering
 
$
5.83

 
$
6.49

 
(10
)%
 
$
6.21

 
$
6.54

 
(5
)%
Production and ad valorem taxes
 
2.80

 
2.19

 
28
 %
 
2.85

 
2.16

 
32
 %
Depreciation, depletion and amortization
 
20.72

 
23.45

 
(12
)%
 
20.95

 
24.84

 
(16
)%
General and administrative per BOE
 
4.06

 
3.75

 
8
 %
 
4.68

 
5.28

 
(11
)%

25



Lease Operating and Gas Gathering
The table below provides detail of our lease operating and gas gathering expense for the three and nine months ended September 30, 2018 and 2017:
In thousands
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
Lease operating
 
$
5,900

 
$
4,052

 
46
%
 
$
15,735

 
$
9,925

 
59
%
Gathering, processing and transportation
 
787

 
524

 
50
%
 
2,026

 
1,128

 
80
%
Total lease operating and gas gathering expense
 
$
6,687

 
$
4,576

 
46
%
 
$
17,761

 
$
11,053

 
61
%
Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for direct l abor, water injection and disposal, utilities, materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production and ad valorem taxes.
Our lease operating and gas gathering expense increased 46%, or $2.1 million, for the three months ended September 30, 2018, to $6.7 million from $4.6 million in the comparable period in 2017. On a nine-month comparative basis, these expenses increased $6.7 million, or 61%, from $11.1 million in 2017 to $17.8 million in 2018. On a unit-of-production basis, lease operating and gas gathering expense decreased 10%, or $0.66 per BOE, from $6.49 per BOE in the three months ended September 30, 2017 to $5.83 per BOE in the three months ended September 30, 2017. For the nine-month comparative, these expenses decreased 5%, or $0.33 per BOE, from $6.54 per BOE in 2017 to $6.21 per BOE in 2018. The increase in total lease operating costs is due to additional operating costs related to additional production acquired in the Battlecat and Marquis transactions in June 2017, as well as costs related to the continuing incremental production brought online by our Eagle Ford development program. Decreases on a unit-of-production basis reflect Lonestar's continued focus on operating efficiencies and leveraging the economies of scale afforded by increased production concentrated in the Eagle Ford.
Compared to the second quarter of 2018, lease operating and gas gathering expense for the three months ended September 30, 2018 increased $0.2 million, or 3%. On a unit of production basis, our lease operating expenses decreased 10%, or $0.64 per BOE from the second quarter of 2018. The increase in total costs reflects the additional operating costs incurred by additional production in the third quarter of 2018, which in-turn was the result of operating a second drilling rig during the quarter and highly-productive new wells, thus lowering lease operating costs relatively on a per BOE basis quarter-to-quarter.
Production and Ad Valorem Taxes
Production and ad valorem taxes are paid on produced crude oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties.
Our production and ad valorem tax expense increased $1.7 million, or 109%, in the three months ended September 30, 2018, to $3.2 million from $1.5 million in the comparable period in 2017. On a nine-month comparative basis, these expenses increased $4.4 million, or 123%, from $3.7 million in 2017 to $8.1 million in 2018. On a unit-of-production basis, production and ad valorem tax expense increased 28%, or $0.61 per BOE, from $2.19 per BOE in the three months ended September 30, 2017 to $2.80 per BOE in the three months ended September 30, 2018. On a nine-month comparative basis, these expenses increased 32%, or $0.69 per BOE, from $2.16 per BOE in 2017 to $2.85 per BOE in 2018. These increases are attributable to increases in valuations of our producing assets as well as higher commodity prices received for our production.
Compared to the second quarter of 2018, production and ad valorem taxes for the three months ended September 30, 2018 increased $0.6 million, or 27%. On a unit of production basis, our production and ad valorem taxes decreased 12%, or $0.37 per BOE, from the second quarter of 2018.

26



Depreciation, Depletion and Amortization
The table below provides detail of our DD&A expense for the three and nine months ended September 30, 2018 and 2017.
In thousands
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
 
 
 
 
(Restated)
 
 
 
 
 
(Restated)
 
 
DD&A of proved oil and gas properties
 
$
23,552

 
$
16,259

 
45
 %
 
$
59,112

 
$
41,339

 
43
%
Depreciation of other property and equipment
 
178

 
233

 
(24
)%
 
693

 
568

 
22
%
Accretion of asset retirement obligations
 
45

 
38

 
18
 %
 
132

 
96

 
38
%
Total DD&A
 
$
23,775

 
$
16,530

 
44
 %
 
$
59,937

 
$
42,003

 
43
%
Capitalized costs attributed to our proved properties are subject to depreciation and depletion calculated using the unit-of-production method. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For well costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Other property and equipment are carried at cost, and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from three to five years.
DD&A expense for the three months ended September 30, 2018 was $23.8 million, a 44% increase from $16.5 million in the comparable period in 2017. On a nine-month comparative basis, these expenses increased $17.9 million, or 43%, from $42.0 million in 2017 to $59.9 million in 2018. This increase is due to an increase in depletable costs associated with our reserve base arising from our Battlecat and Marquis acquisitions in June 2017, as well as continued development of our properties in the Eagle Ford. On a unit-of-production basis, DD&A decreased 12%, or $2.73 per BOE, from $23.45 per BOE for the three months ended September 30, 2017 to $20.72 per BOE for the three months ended September 30, 2018. On a nine-month comparative basis, these expenses decreased 16%, or $3.89 per BOE, from $24.84 per BOE in 2017 to $20.95 per BOE in 2018.
Compared to the second quarter of 2018, DD&A for the three months ended September 30, 2018 increased $3.0 million, or 14%. On a unit of production basis, DD&A increased 1%, or $0.26 per BOE, from the second quarter of 2018.
Impairment of Oil and Gas Properties
During the third quarter of 2018, we recorded an impairment charge of approximately $12.2 million relating to expiring leases in southern Brazos County included in unproved properties. During the second quarter of 2017, we recorded an impairment charge of approximately $27.1 million relating to our West Poplar property in Roosevelt County, Montana.
General and Administrative
G&A expense increased $2.1 million, or 76%, to $4.7 million in the three months ended September 30, 2018, from $2.6 million for the comparable period in 2017. On a nine-month comparative basis, these expenses increased $4.5 million, or 50%, from $8.9 million in 2017 to $13.4 million in 2018. These increases reflect higher stock-based compensation expense for the 2018 periods (discussed below). On a unit-of-production basis, G&A expense increased 8%, or $0.31 per BOE, from $3.75 per BOE in the three months ended September 30, 2017 to $4.06 per BOE in the three months ended September 30, 2018. On a nine-month comparative basis, these expenses decreased 11%, or $0.60 per BOE, from $5.28 per BOE in 2017 to $4.68 per BOE in 2018.
Compared to the second quarter of 2018, G&A expense for the three months ended September 30, 2018 decreased $0.6 million, or 11%. On a unit of production basis, G&A decreased 22%, or $1.17 per BOE, from the second quarter of 2018. This decrease was primarily due to lower employee compensation costs and professional fees in the current quarter.
Stock-based compensation included in G&A was $2.3 million for the three months ended September 30, 2018, versus $0.3 million for the three months ended September 30, 2017. On a nine-month comparative basis, these expenses increased $2.7 million, from $1.0 million in 2017 to $3.7 million in 2018. This increase was due to higher valuations of the Company's unvested restricted stock units and stock appreciation rights as of September 30, 2018.

27



Interest Expense
The table below provides detail of the interest expense for our various long-term obligations for the three and nine months ended September 30, 2018 and 2017.
In thousands
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
Change
 
2018
 
2017
 
Change
Interest expense on 8.75% Senior Notes
 
$

 
$
3,129

 
(100
)%
 
$

 
$
9,809

 
(100
)%
Interest expense on 11.25% Senior Notes
 
7,031

 

 
N/A

 
20,859

 

 
N/A

Interest expense on Second Lien Notes
 

 

 
N/A

 

 
2,016

 
(100
)%
Interest expense on Credit Facility
 
1,895

 
1,831

 
3
 %
 
$
4,296

 
3,535

 
22
 %
Other interest expense
 
253

 
71

 
256
 %
 
497

 
88

 
465
 %
Total cash interest expense (1)
 
$
9,179

 
$
5,031

 
82
 %
 
$
25,652

 
$
15,448

 
66
 %
Amortization of debt issuance costs and discounts
 
1,036

 
934

 
11
 %
 
3,119

 
4,368

 
(29
)%
Total interest expense
 
$
10,215

 
$
5,965

 
71
 %
 
$
28,771

 
$
19,816

 
45
 %
Per BOE:
 
 
 
 
 
 
 
 
 
 
 
 
Total cash interest expense
 
$
8.00

 
$
7.14

 
12
 %
 
$
8.96

 
$
9.14

 
(2
)%
Total interest expense
 
8.90

 
8.46

 
5
 %
 
10.05

 
11.72

 
(14
)%
(1) Cash interest is presented on an accrual basis.
Our total interest expense in the three months ended September 30, 2018 was $10.2 million, a 71% increase from $6.0 million in the comparable period in 2017. On a nine-month comparative basis, these expenses increased $9.0 million, or 45%, from $19.8 million in 2017 to $28.8 million in 2018. These increases are primarily due to a combination of higher stated interest rates and principal on the new 11.25% Senior Notes (as defined below) versus the 8.75% Senior Notes (as defined below) that were retired in January 2018, as well as higher floating rates on our Credit Line (as defined below), offset by lower non-cash interest expense in 2018.
On a unit-of-production basis, total interest expense increased by 5%, or $0.44 per BOE, from $8.46 per BOE in the three months ended September 30, 2017 to $8.90 per BOE in the three months ended September 30, 2018. On a nine-month comparative basis, these expenses decreased 14%, or $1.67 per BOE, from $11.72 per BOE in 2017 to $10.05 per BOE in 2018.
Income Taxes
The Tax Cuts and Jobs Act (the “Act”) was passed in December 2017, which significantly changes U.S. corporate income tax laws generally taking effect in 2018. We included the impacts of the Act in the fourth quarter 2017 consolidated financial statements. We will continue to examine the impact of this legislation and future regulations. The tax provision for the three and nine months ended September 30, 2018 reflects the law changes noted above, including the new corporate tax rate of 21%.

28



The following table provides further detail of our income tax expense for the three and nine months ended September 30, 2018 and 2017.
In thousands, except per-BOE amounts and tax rates
 
Three Months Ended September 30,
 
Nine Months Ended September 30,