EX-99.1 2 q42018resultspressrelease.htm EXHIBIT 99.1 Exhibit



lonestarresourcesa01.jpg
Lonestar Announces Fourth Quarter 2018 Financial Results And Provides Operational Update

Fort Worth, Texas, March 7, 2019 (PRNewswire) - Lonestar Resources US Inc. (NASDAQ: LONE) (including its subsidiaries, "Lonestar," "we," "us," "our" or the "Company") today reported financial and operating results for the three months and year ended December 31, 2018.

HIGHLIGHTS
•
Lonestar reported an 81% increase in net oil and gas production to 13,152 Boe/d during the three months ended December 31, 2018 ("4Q18"), compared to 7,272 Boe/d for the three months ended December 31, 2017 (ì4Q17î). The Company’s record production volumes exceeded the Company’s guidance of 12,600 - 12,800 Boe/d and were 80% crude oil and NGL’s on an equivalent basis.

•
Lonestar reported a net income attributable to its common stockholders of $75.2 million during 4Q18 compared to a net loss of $17.6 million during 4Q17. Excluding, on a tax-adjusted basis, certain items that the Company does not view as either recurring or indicative of its ongoing financial performance, Lonestar’s adjusted net income for 4Q18 was $5.4 million, or $0.22 per basic common share. Most notable among these items include: unrealized hedging gains/losses on financial derivatives and stock-based compensation. Please see Non-GAAP Financial Measures at the end of this release for the definition of Adjusted Net Income (Loss), a reconciliation of net income (loss) before taxes to adjusted net income (loss), and the reasons for its use.

•
Lonestar reported a 99% increase in Adjusted EBITDAX for the three months ended December 31, 2018 of $40.7 million compared to $20.5 million for 4Q17, which was in the higher end of our guidance of $39.0 - $41.0 million and set another record for the Company. This improvement was driven by an 81% increase in production and a 10% reduction in unit cash operating expenses. Please see Non-GAAP Financial Measures at the end of this release for the definition of Adjusted EBITDAX, a reconciliation of net loss to Adjusted EBITDAX, and the reasons for its use.

•
Lonestar has issued production guidance of 11,200 to 12,000 Boe/d for the first quarter of 2019. As commodity prices fell precipitously in the fourth quarter of 2018, Lonestar suspended drilling operations pending the negotiation of contracts for drilling and completion operations which gave the Company sufficient flexibility to "dial-in" activity levels to react to commodity prices and expected cash flow generation capacity. Consequently, Lonestar anticipates the completion of 3 gross/2.9 net wells late in the first quarter of 2019. The midpoint of guidance represents a 49% increase over 1Q18 results.
 
•
Despite a delayed start in completion activity, Lonestar has reiterated its previously-issued 2019 production guidance of 13,700 to 14,700 Boe/d for 2019, which equates to production growth of 27% over 2018 levels. Based the onstream dates associated with its current program, Lonestar has issued Adjusted EBITDAX guidance for 2019 of $140 to $155 million.
  
•
Given the success Lonestar was able to achieve with a dedicated frac spread in 2018, the Company recently executed an agreement with another leading energy service provider for a dedicated frac spread for 2019. This agreement should drive cost down significantly year over year on a per well basis as well as continue to improve

 

our ability to turn wells into production in a timely and efficient fashion, delivering more predictable results to our shareholders.

•
Lonestar continually evaluates its asset portfolio and constantly seeks to improve its capital structure and returns profile. As part of this process, Lonestar has agreed to sell its Pirate assets in Wilson County for $12.3 million. The sale is anticipated to close prior to the end of March 2019. In February, 2019, average daily sales volumes were 219 Boe/d. The Pirate asset is comprised of 3,400 net undeveloped acres and held 7 Proved Undeveloped locations at December 31, 2018.

Lonestar's Chief Executive Officer, Frank D. Bracken, III, commented, "2018 was another year of tremendous per-share growth for Lonestar, coming from a balanced program of drilling and acquisitions. We generated a 81% increase in production and a 99% increase in Adjusted EBITDAX. We extended our track-record of low-cost reserve growth, registering all-sources finding and development costs of $9.07 per BOE while increasing our Proved reserves by 27%. In 2018, we demonstrated substantial improvements in productivity and returns in our core areas, and the focus of our 2019 and 2020 drilling programs will be in these core areas, and additionally on our recently-acquired Sooner property. We have designed our 24-month plan to focus our drilling on areas where we have demonstrated the highest IRR’s in our portfolio, which are in both the crude oil window (Cyclone/Hawkeye and Karnes County), which are 85% oil / 7% NGL’s / 5% gas, and condensate windows (Horned Frog and Sooner), which are 16% oil / 45% NGLs / 39% gas. This returns-focused program is expected to generate 20+% growth in production and EBITDAX through 2020. Importantly, this program is designed to allow the Lonestar to become cash flow self-sufficient in the second half of 2019 and for the full-year in 2020. As a result, we believe that Lonestar will be one of the few companies among its peers who can generate these levels of growth while doing so with internally generated cash flow"

OPERATIONAL UPDATE
•
Lonestar reported net oil and gas production of 13,152 Boe/d during the three months ended December 31, 2018, an increase of 81% compared to 7,272 Boe/d during the three months ended December 31, 2017. 4Q18 production volumes consisted of 7,883 barrels of oil per day (60%), 2,675 barrels of NGLs per day (20%), and 15,561 Mcf of natural gas per day (20%). The Company’s production mix for the three months ended December 31, 2018 was 80% liquid hydrocarbons.

•
Lonestar’s Eagle Ford Shale assets delivered excellent wellhead realizations in 4Q18. Lonestar’s realized wellhead crude oil price was $64.86 per barrel, which reflects a positive differential of $6.05 /bbl vs. West Texas Intermediate. Lonestar’s realized NGL price was $22.48 per barrel, which at 38% of WTI, was the highest quarterly percentage realizations for NGLs in 2018. Lonestar’s realized wellhead natural gas price was $3.72 per Mcf, reflecting a $0.08/Mcf discount to Henry Hub.

•
Lonestar delivered a 10% reduction per Boe in cash operating costs (outlined below) in 4Q18. Total cash expenses, which includes the cash portions of lease operating, gathering, processing, transportation, production taxes, general and administrative, and interest expenses, for the three months ended December 31, 2018 were $25.1 million, which was 63% higher than cash expenses of $15.4 million in the three months ended December 31, 2017. However, on a unit-of-production basis, cash expenses decreased 10% from $20.70 per Boe in the three months ended December 31, 2018 to $23.01 per Boe in the three months ended December 31, 2017.

•
Lease Operating Expenses ("LOE") for the three months ended December 31, 2018 were $7.3 million, which was 50% higher than LOE of $4.9 million in the three months ended December 31, 2017 but was outpaced by an 81% increase in production. On a unit-of-production basis, lease operating expenses decreased 17% to $6.01 per Boe for the three months ended December 31, 2018. For 2019, the Company expects LOE to average between $5.50 and $6.00 per Boe.

•
Gathering, Processing & Transportation Expenses ("G, P&T") for the three months ended December 31, 2018 were $1.0 million, which was 113% higher than the G, P&T of $0.5 million in the three months ended December


31, 2017, commensurate with a 161% increase in gas production. On a unit-of-production basis, G, P&T increased 18% to $0.80 per Boe for the three months ended December 31, 2018. For 2019, the Company expects G, P&T expense to average between $1.00 and $1.25 per Boe.

•
Production taxes for the three months ended December 31, 2018 were $2.9 million, which was 54% higher than production taxes of $1.9 million in the three months ended December 31, 2017, driven largely by an 84% increase in wellhead oil and gas revenues. On a unit-of-production basis, production taxes decreased 15% to $2.38 per Boe for the three months ended December 31, 2018.

•
General & Administrative Expenses, excluding stock-based compensation of $0.6 million in the three months ended December 31, 2017 and ($1.7) million in the three months ended December 31, 2018 ("G&A"), increased from $3.2 million to $4.4 million, respectively. On a unit-of-production basis, G&A per Boe was reduced 25% year over year, from $4.79 per Boe in 2017 to $3.62 per Boe in 2018. For 2019, the Company expects G&A to average between $2.50 and $3.00 per Boe.

•
Interest Expense excluding amortization of debt issuance cost, premiums, and discounts increased year over year from $5.3 million in the three months ended December 31, 2017 to $9.5 million in 2018. On a unit-of-production basis, interest per Boe decreased 1% year over year from $7.95 per Boe in 2017 to $7.89 per Boe in 2018. For 2019, the Company expects interest expense to average between $7.25 and $8.00 per Boe.

•
In the fourth quarter of 2018, Lonestar expanded its Eagle Ford footprint with the Sooner Acquisition, expanding its operational footprint into DeWitt county. Additionally, the Company placed 4 gross / 3.3 net wells online, which included 2 gross / 1.9 net wells in Dimmit County and 2 / 1.4 net wells in Gonzales County. Lonestar expects to continue to grow production organically during 2019 while continuing to look for additional acquisition opportunities within the Eagle Ford. After negotiating updated contracts with its service providers, Lonestar's Board has approved a capital-flexible budget which ranges from 17 gross / 15.6 net wells, which it estimates will cost $107 million, to 20 gross / 18.6 net wells, which are budgeted to cost $130 million.


EAGLE FORD SHALE TREND- WESTERN REGION
In our Western Region, production for the fourth quarter of 2018 averaged approximately 6,825 Boe per day, a 141% increase over the prior year. In October 2018, the Company completed drilling operations on the Asherton #1HN and Asherton #3HN. Through their first 90 days of production, these wells have produced on average 50,000 barrels of oil and 112,550 Mcf of natural gas, or 75,800 barrels of oil equivalent on a three-stream basis, or an average of 843 Boe/d per well over the first 90 days of production.
During 2019 the Company plans to drill 7 gross / 6.9 net wells in its Western region. In La Salle County, the first three wells, the Burns Ranch #11H, Burns Ranch #12H, and Burns Ranch #13H, began flowback operations and are the only wells being brought onstream during the first quarter of 2019. These wells were drilled to average total measured depths of 15,020, 15,030, and 15,036 feet, respectively. The Burns Ranch #11H, #12H, and #13H wells were fracture-stimulated in engineered completions using diverters with an average proppant concentration of 1,485 pounds per foot over 11 stages, 22 stages, and 22 stages, respectively. Lonestar has a 96% WI and 72% NRI in these wells.
Our second set of wells in our Western Region, the Horned Frog NW #4H and Horned Frog NW #5H, finished drilling operations last week and were drilled to total measured depths of 19,716 and 19,672 feet, respectively. Fracture stimulation operations are to begin next week with average proppant concentrations of 2,000 pounds per foot. These wells should begin flowback operations in mid-late April. Lonestar has a 100% WI and 75% NRI in these wells.

EAGLE FORD SHALE TREND- CENTRAL REGION


In our Central Region, production for the fourth quarter of 2018 averaged approximately 5,991 Boe per day, a 56% increase over the prior year. The continued growth of the region was driven by the drilling and completion 2 gross / 1.3 net wells in the Hawkeye area in addition to production acquired in our Sooner Acquisition.
The acquisition, which occurred in November 2018, is 95% operated, included approximately 3,071 gross acres (2,693 net acres) and approximately 800 BOE/d of production on the date of the acquisition. It provides the Company with 26 drilling locations and expands Lonestar’s Eagle Ford footprint into its 11th county, DeWitt. The Company plans to drill its first 3 gross / 3.0 net wells during the third quarter of 2019.
In December, the Company began flowback operations on the Hawkeye #24H and Hawkeye #25H. These wells were drilled to total measured depths of 20,050 and 19,665 feet, respectively. The Hawkeye #24H and #25H wells were fracture-stimulated in engineered completions using diverters with an average proppant concentration of 1,517 pounds per foot over 37 stages and 33 stages, respectively. The Hawkeye #24H was completed with a perforated interval of 10,407 feet and tested 937 Bbls/d of oil and 444 Mcf/d of natural gas, or 1,038 Boe/d (three-stream) on a 28/64’’ choke. The Hawkeye #25H was completed with a perforated interval of 9,901 feet and tested 912 Bbls/d of oil and 385 Mcf/d of natural gas, or 1,000 Boe/d (three-stream) on a 26/64’’ choke. Collectively, these wells have average Max-30 IP’s of 764 Bbls/d oil and 397 Mcf/d of natural gas, or 855 Boe/d (three-stream) on a 32/64’’ choke. Lonestar holds a 68% WI / 53% NRI in these wells.
During 2019 the Company plans to drill 12 gross / 11.2 net wells in its Central region. Lonestar is currently drilling its first set of wells in the region for 2019, the Georg #3H, Georg #4H, Georg #5H, and Georg #6H. These wells have planned total measured depths of approximately 16,400 feet and expected perforated intervals of 7,250 feet. Lonestar has an 80% WI / 61% NRI in these wells.

EAGLE FORD SHALE TREND- EASTERN REGION
In our Eastern Region, production for the fourth quarter of 2018 averaged approximately 336 Boe per day, a 43% decrease over the prior year. The Company did not complete any wells in this region in 2018. Lonestar plans to return to Brazos during 2Q19 to drill a 1 gross / 0.5 net well. Lonestar will have a 50% WI / 39% NRI in this well.

CONFERENCE CALL DETAILS
Lonestar will host a live conference call on Friday, March 8, 2019 at 9:00 AM CDT to discuss the fourth quarter 2018 results and operational highlights.
To access the conference call, participants should dial:
USA: 877-256-6033
International: +1-303-223-2698
A playback of the conference call will be available on the Investor Relations section of Company’s website beginning approximately March 11, 2019.

ABOUT LONESTAR RESOURCES US, INC.
Lonestar is an independent oil and natural gas company, focused on the development, production and acquisition of unconventional oil, NGLs and natural gas properties in the Eagle Ford Shale in Texas, where we accumulated approximately 78,193 gross (57,491 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of December 31, 2018. For more information, please visit www.lonestarresources.com.
Cautionary & Forward-Looking Statements
Lonestar Resources US Inc. cautions that this press release contains forward-looking statements, including, but not limited to; Lonestar’s execution of its growth strategies; growth in Lonestar’s leasehold, reserves and asset value; and


Lonestar’s ability to create shareholder value. These statements involve substantial known and unknown risks, uncertainties and other important factors that may cause our actual results, levels of activity, performance or achievements to be materially different from the information expressed or implied by these forward-looking statements. These risks and uncertainties include, but are not limited to, the following: volatility of oil, natural gas and NGL prices, and potential write-down of the carrying values of crude oil and natural gas properties; inability to successfully replace proved producing reserves; substantial capital expenditures required for exploration, development and exploitation projects; potential liabilities resulting from operating hazards, natural disasters or other interruptions; risks related using the latest available horizontal drilling and completion techniques; uncertainties tied to lengthy period of development of identified drilling locations; unexpected delays and cost overrun related to the development of estimated proved undeveloped reserves; concentration risk related to properties, which are located primarily in the Eagle Ford Shale of South Texas; loss of lease on undeveloped leasehold acreage that may result from lack of development or commercialization; inaccuracies in assumptions made in estimating proved reserves; our limited control over activities in properties Lonestar does not operate; potential inconsistency between the present value of future net revenues from our proved reserves and the current market value of our estimated oil and natural gas reserves; risks related to derivative activities; losses resulting from title deficiencies; risks related to health, safety and environmental laws and regulations; additional regulation of hydraulic fracturing; reduced demand for crude oil, natural gas and NGLs resulting from conservation measures and technological advances; inability to acquire adequate supplies of water for our drilling operations or to dispose of or recycle the used water economically and in an environmentally safe manner; climate change laws and regulations restricting emissions of "greenhouse gases" that may increase operating costs and reduce demand for the crude oil and natural gas; fluctuations in the differential between benchmark prices of crude oil and natural gas and the reference or regional index price used to price actual crude oil and natural gas sales; and the other important factors discussed under the caption "Risk Factors" in our Annual Report on Form 10-K/A filed with the Securities and Exchange Commission, or the SEC, on November 2, 2018, as well as other documents that we may file from time to time with the SEC. We may not actually achieve the plans, intentions or expectations disclosed in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Actual results or events could differ materially from the plans, intentions and expectations disclosed in the forward-looking statements we make. The forward-looking statements in this press release represent our views as of the date of this press release. We anticipate that subsequent events and developments will cause our views to change. However, while we may elect to update these forward-looking statements at some point in the future, we have no current intention of doing so except to the extent required by applicable law. You should, therefore, not rely on these forward-looking statements as representing our views as of any date subsequent to the date of this press release.
    
                
(Financial Statements to Follow)




Lonestar Resources US Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
 
December 31,
 
2018
 
2017
Assets
Current assets
 
 
 
Cash and cash equivalents
$
5,355

 
 
$
2,538

 
Accounts receivable
 
 
 
Oil, natural gas liquid and natural gas sales
15,103
 
 
 
12,289
 
 
Joint interest owners and other, net
4,541
 
 
 
794
 
 
Related parties
301
 
 
 
162
 
 
Derivative financial instruments
15,841
 
 
 
472
 
 
Prepaid expenses and other
1,966
 
 
 
2,365
 
 
Total current assets
43,107
 
 
 
18,620
 
 
Property and equipment
 
 
 
Oil and gas properties, using the successful efforts method of accounting
 
 
 
Proved properties
960,711
 
 
 
747,370
 
 
Unproved properties
81,850
 
 
 
81,511
 
 
Other property and equipment
17,727
 
 
 
15,763
 
 
Less accumulated depreciation, depletion, amortization and impairment
(369,529
)
 
 
(274,374
)
 
Property and equipment, net
690,759
 
 
 
570,270
 
 
Derivative financial instruments
7,302
 
 
 
0
 
 
Other non-current assets
2,944
 
 
 
2,918
 
 
Total assets
$
744,112

 
 
$
591,808

 
Liabilities and Stockholders’ Equity
Current liabilities
 
 
 
Accounts payable
$
18,260

 
 
$
25,901

 
Accounts payable - related parties
181
 
 
 
389
 
 
Oil, natural gas liquid and natural gas sales payable
13,022
 
 
 
8,747
 
 
Accrued liabilities
28,128
 
 
 
16,583
 
 
Derivative financial instruments
430
 
 
 
12,336
 
 
Total current liabilities
60,021
 
 
 
63,956
 
 
Long-term liabilities
 
 
 
Long-term debt
436,882
 
 
 
301,155
 
 
Asset retirement obligations
7,195
 
 
 
5,649
 
 
Deferred tax liability, net
12,370
 
 
 
4,769
 
 
Equity warrant liability
366
 
 
 
508
 
 
Equity warrant liability - related parties
689
 
 
 
963
 
 
Derivative financial instruments
21
 
 
 
9,802
 
 
Other non-current liabilities
4,021
 
 
 
1,316
 
 
Total long-term liabilities
461,544
 
 
 
324,162
 
 
Commitments and contingencies
 
 
 
Stockholders’ equity
 
 
 
Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 24,645,825 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 issued and outstanding, respectively
0
 
 
 
0
 
 
Series A-1 convertible participating preferred stock, $0.001 par value, 91,784 and 83,968 shares issued and outstanding, respectively
0
 
 
 
0
 
 
Additional paid-in capital
174,379
 
 
 
174,871
 
 
Accumulated deficit
(94,487
)
 
 
(113,836
)
 
Total stockholders’ equity
222,547
 
 
 
203,690
 
 
Total liabilities and stockholders’ equity
$
744,112

 
 
$
591,808

 



Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per share data)

 
3 Months Ended December 31,
 
Year Ended December 31,
 
2018
 
2017
 
2018
 
2017
Revenues
 
 
 
 
 
 
 
Oil sales
$
47,038

 
 
$
27,763

 
 
$
167,743

 
 
$
80,505

 
Natural gas liquid sales
5,319
 
 
 
1,406
 
 
 
18,471
 
 
 
7,086
 
 
Natural gas sales
5,532
 
 
 
2,265
 
 
 
14,955
 
 
 
6,477
 
 
Total revenues
57,889
 
 
 
31,434
 
 
 
201,169
 
 
 
94,068
 
 
Expenses
 
 
 
 
 
 
 
Lease operating and gas gathering
8,247
 
 
 
6,331
 
 
 
26,008
 
 
 
17,385
 
 
Production and ad valorem taxes
2,884
 
 
 
1,867
 
 
 
11,029
 
 
 
5,523
 
 
Depreciation, depletion and amortization
23,645
 
 
 
14,954
 
 
 
83,582
 
 
 
56,957
 
 
Loss on sale of oil and gas properties
—
 
 
 
—
 
 
 
—
 
 
 
466
 
 
Impairment of oil and gas properties
—
 
 
 
6,332
 
 
 
12,169
 
 
 
33,413
 
 
General and administrative
2,632
 
 
 
3,840
 
 
 
16,017
 
 
 
12,626
 
 
Acquisition costs and other
(47
)
 
 
—
 
 
 
1,821
 
 
 
3,139
 
 
Total expenses
37,361
 
 
 
33,324
 
 
 
150,626
 
 
 
129,509
 
 
Income (loss) from operations
20,528
 
 
 
(1,890
)
 
 
50,543
 
 
 
(35,441
)
 
Other income (expense)
 
 
 
 
 
 
 
Interest expense
(10,173
)
 
 
(6,255
)
 
 
(38,943
)
 
 
(26,071
)
 
Unrealized gain (loss) on warrants
2,522
 
 
 
(198
)
 
 
416
 
 
 
3,088
 
 
Gain (loss) on derivative financial instruments
77,596
 
 
 
(20,585
)
 
 
22,744
 
 
 
(14,080
)
 
Loss on extinguishment of debt
—
 
 
 
—
 
 
 
(8,620
)
 
 
—
 
 
Total other income (expense), net
69,945
 
 
 
(27,038
)
 
 
(24,403
)
 
 
(37,063
)
 
Income (loss) before income taxes
90,473
 
 
 
(28,928
)
 
 
26,140
 
 
 
(72,504
)
 
Income tax (expense) benefit
(13,283
)
 
 
13,165
 
 
 
(6,792
)
 
 
29,019
 
 
Net income (loss)
77,190
 
 
 
(15,763
)
 
 
19,348
 
 
 
(43,485
)
 
Preferred stock dividends
(2,020
)
 
 
(1,848
)
 
 
(7,816
)
 
 
(3,968
)
 
Net income (loss) attributable to common stockholders
$
75,170

 
 
$
(17,611
)
 
 
$
11,532

 
 
$
(47,453
)
 





Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
 
3 Months Ended December 31,
 
Year Ended December 31,
2018
 
2017
 
2018
 
2017
Cash flows from operating activities
 
 
 
 
 
 
 
Net income (loss)
$
77,190

 
 
$
(15,763
)
 
 
$
19,348

 
 
$
(43,485
)
 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
 
 
 
Depreciation, depletion and amortization
23,645
 
 
 
14,954
 
 
 
83,582
 
 
 
56,957
 
 
Stock-based compensation
(1,932
)
 
 
644
 
 
 
1,707
 
 
 
1,629
 
 
Share-based payments
—
 
 
 
—
 
 
 
(601
)
 
 
—
 
 
Deferred taxes
14,746
 
 
 
(13,075
)
 
 
7,601
 
 
 
(29,191
)
 
(Gain) loss on derivative financial instruments
(77,596
)
 
 
20,585
 
 
 
(22,744
)
 
 
14,080
 
 
Settlements of derivative financial instruments
(5,292
)
 
 
313
 
 
 
(22,623
)
 
 
5,207
 
 
Impairment of oil and gas properties
—
 
 
 
6,332
 
 
 
12,169
 
 
 
33,413
 
 
Loss on abandoned property and equipment
—
 
 
 
—
 
 
 
170
 
 
 
—
 
 
Non-cash interest expense
638
 
 
 
196
 
 
 
5,194
 
 
 
4,571
 
 
Unrealized (gain) loss on warrants
(2,522
)
 
 
198
 
 
 
(416
)
 
 
(3,088
)
 
Changes in operating assets and liabilities:
 
 
 
 
 
 
 
Accounts receivable
(2,103
)
 
 
(1,637
)
 
 
(5,391
)
 
 
(6,851
)
 
Prepaid expenses and other assets
(1,460
)
 
 
4,393
 
 
 
(3,296
)
 
 
833
 
 
Accounts payable and accrued expenses
6,939
 
 
 
(2,160
)
 
 
13,372
 
 
 
9,371
 
 
Net cash provided by operating activities
32,253
 
 
 
14,979
 
 
 
88,072
 
 
 
43,446
 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
 
 
Acquisition of oil and gas properties
(40,776
)
 
 
(4,695
)
 
 
(45,539
)
 
 
(113,726
)
 
Development of oil and gas properties
(48,722
)
 
 
(24,957
)
 
 
(171,413
)
 
 
(81,875
)
 
Purchases of other property and equipment
(887
)
 
 
(1,562
)
 
 
(2,518
)
 
 
(13,142
)
 
Net cash used in investing activities
(90,385
)
 
 
(31,214
)
 
 
(219,470
)
 
 
(208,743
)
 
 
 
 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 
 
 
Proceeds from borrowings and related party borrowings
75,000
 
 
 
20,980
 
 
 
423,745
 
 
 
123,968
 
 
Payments on borrowings and related party borrowings
(16,053
)
 
 
(6,513
)
 
 
(289,520
)
 
 
(34,017
)
 
Proceeds from sale of preferred stock
—
 
 
 
—
 
 
 
—
 
 
 
77,800
 
 
Repurchase and retire Class B Common Stock
—
 
 
 
—
 
 
 
(10
)
 
 
—
 
 
Cost to issue equity
—
 
 
 
(506
)
 
 
—
 
 
 
(3,296
)
 
Payments of debt issuance costs
—
 
 
 
—
 
 
 
—
 
 
 
(2,688
)
 
Net cash provided by financing activities
58,947
 
 
 
13,961
 
 
 
134,215
 
 
 
161,767
 
 
Net (decrease) in cash and cash equivalents
813
 
 
 
(2,274
)
 
 
2,817
 
 
 
(3,530
)
 
Cash and cash equivalents, beginning of the period
4,542
 
 
 
4,812
 
 
 
2,538
 
 
 
6,068
 
 
Cash and cash equivalents, end of the period
$
5,355

 
 
$
2,538

 
 
$
5,355

 
 
$
2,538

 
 
 
 
 
 
 
 
 
Supplemental information:
 
 
 
 
 
 
 
Cash paid for taxes
$
95

 
 
$
9

 
 
$
1,242

 
 
$
2,474

 
Cash paid for interest
2,071
 
 
 
9,329
 
 
 
24,395
 
 
 
20,389
 
 
Non-cash investing and financing activities:
 
 
 
 
 
 
 
Preferred stock issued for business acquisitions
—
 
 
 
—
 
 
 
—
 
 
 
10,795
 
 
Asset retirement obligation
1,109
 
 
 
509
 
 
 
1,331
 
 
 
2,827
 
 
Increase (decrease) in liabilities for capital expenditures
(21,591
)
 
 
6,709
 
 
 
(4,603
)
 
 
8,379
 
 





NON-GAAP FINANCIAL MEASURES (Unaudited)
Reconciliation of Non-GAAP Financial Measures

Adjusted EBITDAX
Adjusted EBITDAX is not a measure of net income as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDAX as net (loss) income before depreciation, depletion, amortization and accretion, exploration costs, non-recurring costs, (gain) loss on sales of oil and natural gas properties, impairment of oil and gas properties, stock-based compensation, interest expense, income tax (benefit) expense, rig standby expense, other income (expense), unrealized (gain) loss on derivative financial instruments and unrealized (gain) loss on warrants.

Management believes Adjusted EBITDAX provides useful information to investors because it assists investors in the evaluation of the Company’s operating performance and comparison of the results of the Company’s operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income in arriving at Adjusted EBITDAX to eliminate the impact of certain non-cash items or because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. The Company’s computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated.

 
 
Three Months Ended December 31,
 
Year Ended December 31,
($ in thousands)
 
2018
 
2017
 
2018
 
2017
Net (Loss) Income
 
$
75,170

 
 
$
(17,611
)
 
 
$
11,532

 
 
$
(47,453
)
 
Income tax expense (benefit)
 
13,283
 
 
 
(13,165
)
 
 
6,792
 
 
 
(29,019
)
 
Interest expense (1)
 
12,192
 
 
 
8,102
 
 
 
46,759
 
 
 
30,039
 
 
Exploration expense
 
—
 
 
 
416
 
 
 
109
 
 
 
627
 
 
Depreciation, depletion and amortization
 
23,645
 
 
 
14,954
 
 
 
83,582
 
 
 
56,957
 
 
EBITDAX
 
$
124,290

 
 
$
(7,304
)
 
 
$
148,774

 
 
$
11,151

 
Rig standby expense
 
—
 
 
 
561
 
 
 
27
 
 
 
622
 
 
Non-recurring costs (2)
 
436
 
 
 
173
 
 
 
782
 
 
 
3,637
 
 
Stock-based compensation
 
(1,746
)
 
 
644
 
 
 
1,908
 
 
 
1,629
 
 
(Gain) loss on sale of oil and gas properties
 
—
 
 
 
—
 
 
 
—
 
 
 
466
 
 
Impairment of oil and gas properties
 
—
 
 
 
6,332
 
 
 
12,169
 
 
 
33,413
 
 
Unrealized (gain) loss on derivative financial instruments
 
(79,776
)
 
 
19,860
 
 
 
(43,376
)
 
 
17,188
 
 
Unrealized (gain) loss on warrants
 
(2,522
)
 
 
198
 
 
 
(416
)
 
 
(3,088
)
 
Other (income) expense
 
(31
)
 
 
—
 
 
 
10,397
 
 
 
(54
)
 
Adjusted EBITDAX
 
$
40,651

 
 
$
20,464

 
 
$
130,265

 
 
$
64,964

 


1 Interest expense also includes dividends paid on Series A Preferred Stock
2 Non-recurring costs consists of Acquisitions Costs.



Adjusted Net Income (Loss)
Adjusted net income (loss) comparable to analysts’ estimates as set forth in this release represents income or loss from operations before income taxes adjusted for certain non-cash items (detailed in the accompanying table) less income taxes. We believe adjusted net income (loss) is calculated on the same basis as analysts’ estimates and that many investors use this published research in making investment decisions and evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Diluted earnings per share (adjusted) as set forth in this release represents adjusted net income (loss) comparable to analysts’ estimates on a diluted per share basis.

The following table presents a reconciliation of Adjusted Net Income (Loss) to the GAAP financial measure of net income (loss) before taxes for each of the periods indicated.

Lonestar Resources US Inc.
Unaudited Reconciliation of Income (Loss) Before Taxes As Reported To Income (Loss) Before Taxes Excluding Certain Items, a non-GAAP measure (Adjusted Net Income (Loss))

 
 
Three Months Ended December 31,
 
Year Ended December 31,
 
 
2018
 
2017
 
2018
 
2017
 
 
(In thousands)
 
 
 
(In thousands)
Income (loss) before income taxes, as reported
 
$
90,473

 
 
$
(30,307
)
 
 
$
26,140

 
 
$
(72,504
)
 
Adjustments for special items:
 
 
 
 
 
 
 
 
Impairment of oil and gas properties
 
—
 
 
6,332
 
 
12,169
 
 
33,413
 
Early payment premium on Second Lien Notes
 
—
 
 
—
 
 
—
 
 
1,050
 
Warrant discount recognition due to early payment on Second Lien Notes
 
—
 
 
—
 
 
—
 
 
1,991
 
Legal expenses for corporate governance and public reporting setup
 
—
 
 
229
 
 
—
 
 
628
 
General & administrative non-recurring costs
 
436
 
 
337
 
 
503
 
 
886
 
Rig standby expense
 
—
 
 
561
 
 
27
 
 
622
 
Non-recurring legal expense
 
—
 
 
—
 
 
233
 
 
—
 
Loss on extinguishment of debt
 
—
 
 
—
 
 
8,620
 
 
—
 
Unrealized hedging (gain) loss
 
(79,776
)
 
19,860
 
 
(43,376
)
 
17,188
 
Lease write-off
 
—
 
 
—
 
 
1,568
 
 
—
 
Stock-based compensation
 
(1,746
)
 
644
 
 
1,908
 
 
1,629
 
Advisory fees for completion of acquisition
 
—
 
 
—
 
 
—
 
 
2,726
 
Income (loss) before income taxes, as adjusted
 
9,387
 
 
(2,344
)
 
7,792
 
 
(12,371
)
 
 
 
 
 
 
 
 
 
Income tax (expense) benefit, as adjusted
 
 
 
 
 
 
 
 
Deferred income tax (expense) benefit, as adjusted (a)
 
(1,971
)
 
820
 
 
(1,636
)
 
4,330
 
Net income (loss) excluding certain items, a non-GAAP measure
 
7,416
 
 
(1,524
)
 
6,156
 
 
(8,041
)
 
 
 
 
 
 
 
 
 
Preferred stock dividends
 
(2,020
)
 
(1,848
)
 
(7,816
)
 
(3,968
)
Net income (loss) after preferred dividends excluding certain items, a non-GAAP measure
 
$
5,396

 
 
$
(3,372
)
 
 
$
(1,660
)
 
 
$
(12,009
)
 
(a)
Effective tax rate for 2018 and 2017 is estimated to be approximately 21% and 35%, respectively.





Lonestar Resources US Inc.
Unaudited Operating Results
 
 
Three Months Ended December 31,
 
Year Ended December 31,
In thousands, except per share and unit data
 
2018
 
2017
 
2018
 
2017
Operating results
 
 
 
 
 
 
 
 
Net income (loss) attributable to common stockholders
 
$
75,169

 
 
$
(17,611
)
 
 
$
11,533

 
 
$
(47,453
)
 
Operating revenues
 
 
 
 
 
 
 
 
Oil
 
$
47,038

 
 
$
27,764

 
 
$
167,743

 
 
$
80,505

 
NGLs
 
5,533
 
 
 
1,405
 
 
 
18,471
 
 
 
7,086
 
 
Natural gas
 
5,318
 
 
 
2,265
 
 
 
14,955
 
 
 
6,477
 
 
Total operating revenues
 
$
57,889

 
 
$
31,434

 
 
$
201,169

 
 
$
94,068

 
Total production volumes by product
 
 
 
 
 
 
 
 
Oil (Bbls)
 
725,236
 
 
479,964
 
 
2,483,799
 
 
1,579,720
 
NGLs (Bbls)
 
246,100
 
 
97,704
 
 
817,431
 
 
390,185
 
Natural gas (Mcf)
 
1,431,612
 
 
548,044
 
 
4,622,815
 
 
2,404,620
 
Total barrels of oil equivalent (6:1)
 
1,209,938
 
 
669,009
 
 
4,071,700
 
 
2,370,675
 
Daily production volumes by product
 
 
 
 
 
 
 
 
Oil (Bbls/d)
 
7,883
 
 
5,217
 
 
6,805
 
 
4,328
 
NGLs (Bbls/d)
 
2,675
 
 
1,062
 
 
2,239
 
 
1,069
 
Natural gas (Mcf/d)
 
15,561
 
 
5,957
 
 
12,665
 
 
6,588
 
Total barrels of oil equivalent (BOE/d)
 
13,152
 
 
7,272
 
 
11,155
 
 
6,495
 
Average realized prices
 
 
 
 
 
 
 
 
Oil ($ per Bbl)
 
$
64.86

 
 
$
57.85

 
 
$
67.53

 
 
$
50.96

 
NGLs ($ per Bbl)
 
22.48
 
 
23.18
 
 
 
22.6
 
 
18.48
 
Natural gas ($ per Mcf)
 
3.72
 
 
2.56
 
 
3.24
 
 
2.73
 
Total oil equivalent, excluding the effect from hedging ($ per BOE)
 
47.84
 
 
46.99
 
 
49.41
 
 
39.77
 
Total oil equivalent, including the effect from hedging ($ per BOE)
 
46.04
 
 
46.22
 
 
41.08
 
 
41.08
 
Operating and other expenses
 
 
 
 
 
 
 
 
Lease operating and gas gathering
 
$
8,247

 
 
$
6,331

 
 
$
26,008

 
 
$
17,385

 
Production and ad valorem taxes
 
2,884
 
 
 
1,868
 
 
 
11,029
 
 
 
5,523
 
 
Depreciation, depletion and amortization
 
23,645
 
 
 
16,333
 
 
 
83,582
 
 
 
56,957
 
 
General and administrative
 
2,632
 
 
 
3,840
 
 
 
16,017
 
 
 
12,626
 
 
Interest expense
 
10,173
 
 
 
6,255
 
 
 
38,943
 
 
 
26,071
 
 
Operating and other expenses per BOE
 
 
 
 
 
 
 
 
Lease operating and gas gathering
 
$
6.82

 
 
$
9.46

 
 
$
6.39

 
 
$
7.33

 
Production and ad valorem taxes
 
2.38
 
 
2.79
 
 
2.71
 
 
2.33
 
Depreciation, depletion and amortization
 
19.54
 
 
24.41
 
 
 
20.53
 
 
24.03
 
General and administrative
 
2.18
 
 
5.74
 
 
 
3.93
 
 
5.33
 
Interest expense
 
8.41
 
 
 
9.35
 
 
 
9.56
 
 
11.00
 
 
(1)
General and administrative expenses include stock-based compensation
(2)
Interest expense includes amortization of debt issuance cost, premiums, and discounts