Lonestar Announces First Quarter 2019 Financial Results And Provides Operational Update
FORT WORTH, Texas, May 13, 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 ended March 31, 2019.
HIGHLIGHTS
-- Lonestar reported a 46% increase in net oil and gas production to 11,372
BOE/d during the three months ended March 31, 2019 ("1Q19"), compared to
7,777 BOE/d for the three months ended March 31, 2018 ("1Q18"). The
production volumes were within Company guidance of 11,200 - 12,000 BOE/d
and were comprised of 79% crude oil and NGL's on an equivalent basis.
With the addition of six new wells, current net oil and gas production
has climbed to 14,000 BOE/d.
-- During 1Q19, Lonestar experienced an unusually high number of instances
in which its producing wells were hit by frac operations conducted by
third parties. In total, 9 of the Company's pads were affected, and a
total of 23 of our wells in the Western and Central regions experienced
production curtailments related to these 'frac hits'. These offset frac
hits resulted in an aggregated reduction of 330 BOE/d in our 1Q19
production, reducing quarterly revenue by $1.4 million and increasing
Lease Operating Expenses ("LOE") by $0.6 million. Notably, all wells
have since been returned to production equal to or above their
third-party type curves.
-- Lonestar reported a net loss attributable to its common stockholders of
$60.6 million during 1Q19 compared to a net loss of $18.4 million during
1Q18, or a net loss of $2.45 and $0.75 per share, respectively. Our
first quarter net loss included a $32.9 million loss attributable to the
sale of our Pirate properties in March 2019, while our 2018 net loss
included an $8.6 million loss on extinguishment of debt. 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 loss for 1Q19 was $3.4 million, or $0.14 per
share. Most notable among these items include: $35.5 million of
unrealized hedging gains/losses on financial derivatives related to
mark-to-market accounting on our hedge book and $0.9 million associated
with stock-based compensation. Please see Non-GAAP Financial Measures at
the end of this release for the definition of Adjusted Net Income (Loss)
to adjusted net income (loss), a reconciliation of net income before
taxes to adjusted net income(loss), and the reasons for its use.
-- Lonestar reported a 15% increase in Adjusted EBITDAX for the three
months ended March 31, 2019 of $27.0 million compared to $23.4 million
for 1Q18. This improvement was driven by a 46% increase in production
coupled with an 11% 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's Chief Executive Officer, Frank D. Bracken, III, commented, "While our first quarter 2019 results represented significant improvement over the year prior, it represented a temporary pause in what the market has come to expect in terms of our ongoing financial growth and maturation. In fact, very little of our planned completion activity contributed to our first quarter results. Just 3 of our planned 20 completions for the year added to first quarter production, and those completions represented just 11% of the total perforated interval we plan to bring onstream over the course of 2019. The quarter was also impacted by an unprecedented number of frac hits from offset wells. I am pleased to report that Lonestar's wells not only weathered those hits but now have been restored to full rate. In the second quarter, completion activity has accelerated significantly, with 6.0 gross / 5.2 net wells commencing flowback in May. These wells represent total perforated interval of 47,600 feet, or 27% of our anticipated total for 2019. Current net production is a record 14,000 BOE/d, and accordingly, we expect the second quarter to reflect significant sequential growth in production and Adjusted EBITDAX, which will accelerate in the third quarter, when we expect to set an all-time record for both."
OPERATIONAL UPDATE
-- Lonestar reported net oil and gas production of 11,372 BOE/d during the
three months ended March 31, 2019, an increase of 46% compared to 7,777
BOE/d during the three months ended March 31, 2018. 1Q19 production
volumes consisted of 6,557 barrels of oil per day (58%), 2,417 barrels
of NGLs per day (21%), and 14,391 Mcf of natural gas per day (21%). The
Company's production mix for the three months ended March 31, 2019 was
79% liquid hydrocarbons.
-- Lonestar's Eagle Ford Shale assets continued to deliver outstanding
wellhead realizations in 1Q19. Lonestar's wellhead crude oil price
realization was $56.90 per barrel, which reflects a premium of $2.00
/bbl vs. West Texas Intermediate. Lonestar's realized NGL price was
$15.60 per barrel, or 28% of WTI. This was largely driven by a drop in
Propane and other heavy liquids pricing which fell as much as 23% from
1Q18 prices. Lonestar's realized wellhead natural gas price was $2.91
per Mcf, reflecting a $0.01/Mcf discount to Henry Hub.
-- Operating revenues increased by $4.0 million to $40.7 million, or 11%,
between the two quarters, primarily driven by a 46% increase in
production partially offset with a 35% decrease in commodity prices.
-- In 1Q19, Lonestar demonstrated continued progress in scaling its
business to make it more competitive, delivering an 11% reduction in per
BOE cash operating costs (outlined below). Total cash expenses, which
includes the cash portions of lease operating, gathering, processing,
transportation, production taxes, general & administrative, and interest
expenses were $23.4 million for the three months ended March 31, 2019.
While cash operating costs rose 30% compared to $17.9 million in the
three months ended March 31, 2018, Lonestar's 46% increase in production
yielded an 11% reduction in cash operating costs per unit, reducing
total cash expenses from $25.61 per BOE in 1Q18 to $22.76 per BOE in
1Q19.
-- Lease Operating Expenses, excluding rig standby costs of $0.1
million, were $6.7 million for the three months ended March 31,
2019, which was 62% higher than LOE of $4.1 million in the three
months ended March 31, 2018. During 1Q19, Lonestar was hit by third
party fracs across 9 of its pads, a total of 23 wells in its Western
and Central regions. These offset frac hits resulted in an
additional $0.6 million of LOE or $0.54 on a per BOE basis. These
unplanned lease operating expenses were almost exclusively
responsible for the 11% increase in LOE to $6.57 per BOE for the
three months ended March 31, 2019.
-- Gathering, Processing & Transportation Expenses ("G, P&T") for the
three months ended March 31, 2019 were $0.9 million, which was 99%
higher than the G, P&T of $0.4 million in the three months ended
March 31, 2018, related to a 124% increase in gas production. On a
unit-of-production basis, G, P&T increased 36% to $0.86 per BOE for
the three months ended March 31, 2019.
-- Production taxes for the three months ended March 31, 2019 were $2.3
million, which was 6% higher than production taxes of $2.2 million
in the three months ended March 31, 2018. On a unit-of-production
basis, production taxes decreased 28% to $2.24 per BOE for the three
months ended March 31, 2019.
-- General & Administrative Expenses in the three months ended March
31, 2018 were $3.4 million vs. $4.4 million in the three months
ended March 31, 2019. General & Administrative Expenses, excluding
stock-based compensation of $0.5 million in the three months ended
March 31, 2018 and $0.9 million in the three months ended March 31,
2019 ("G&A"), increased from $3.0 million to $3.5 million,
respectively. On a unit-of-production basis, G&A per BOE fell 21%
year over year, from $4.24 per BOE in 2018 to $3.37 per BOE in 2019.
-- Interest Expense was $9.3 million in the three months ended March
31, 2018 vs. $10.7 million in the three months ended March 31, 2019.
Interest Expense excluding amortization of debt issuance cost,
premiums, and discounts, increased year over year from $8.2 million
in 1Q18 to $10.0 million in 1Q19. On a unit-of-production basis,
interest per BOE decreased 17% year over year from $11.72 per BOE in
2018 to $9.73 per BOE in 2019.
-- Lonestar is committed to managing its liquidity and high-grading its
portfolio. On March 22, 2019, we completed the divestiture of our Pirate
assets in Wilson County for $12.3 million, before closing adjustments,
to a private third-party. The assets were comprised of 3,400 net
undeveloped acres and held 7 proved undeveloped locations as of the
closing date, and were producing approximately 200 BOE/d.
GUIDANCE
-- Lonestar responded to low oil prices in 4Q18 by deferring drilling and
completion activities. Consequently, in 1Q19, the Company only completed
3 gross / 2.9 short laterals in La Salle County that began producing in
March. However, Lonestar has ramped up to its activity and expects to
continue to increase production organically during the second quarter,
and through the remainder of 2019. The Company anticipates placing 6.0
gross / 5.2 net wells online during 2Q19. In April, 2 gross / 2.0 net
wells at Horned Frog NW were placed into flowback. In May, 4 gross / 3.2
net wells in Karnes County have been placed into flowback operations.
The Company has recently completed drilling operations on 2 gross / 2.0
net wells at Horned Frog with projected completed intervals exceeding
12,000 feet, with completion operations expected to commence before the
end of May. Flowback operations for these two wells are expected to
commence on or around July 1, 2019, and these wells are expected to
contribute materially to the third quarter production volumes.
-- Lonestar issued production guidance of 12,400 to 12,800 BOE/d for the
second quarter of 2019, a 12% increase over 2Q18 results at the
midpoint. The primary sources for production growth in the second
quarter will be 2.0 net wells at Horned Frog NW, which will contribute
volumes for essentially the whole quarter, and 3.2 net wells in Karnes
County, which are expected to contribute volumes for roughly half of the
second quarter.
-- Lonestar issued Adjusted EBITDAX guidance of $30 to $32 million for the
second quarter of 2019, a 15% sequential increase over 1Q19 results.
During the quarter, the Company anticipates oil realizations of
+$2.10/bbl to WTI and lease operating expenses of $6.00/BOE.
EAGLE FORD SHALE TREND- WESTERN REGION
In our Western Region, production for the first quarter of 2019 averaged approximately 5,722 BOE per day, a 74% increase over the prior year. During 1Q19, Lonestar was hit by third party fracs across 9 of its pads, a total of 23 wells in its Western and Central regions. These offset frac hits led to curtailed production of approximately 330 BOE/d during the quarter and will also modestly impact sales in April. In aggregate, these wells have since recovered and returned to their third-party type curves. After completing 3 gross / 2.9 net wells at Burns Ranch during the first quarter, the Company focused its Western Region drilling activities to its Horned Frog region, which has some of the highest internal rate of returns ("IRR") in the Company's profile.
In April, the Company began flowback operations on the Horned Frog NW #4H and #5H. The Company holds a 100% working interest ("WI") / 75% net revenue interest ("NRI") in these wells. These wells were drilled to an average total measured depth of 19,716 and 19,672 feet and were fracture-stimulated using diverters with an average proppant concentration of 2,030 pounds per foot over 33 stages. Perforations and test rates for the for wells are:
-- Horned Frog NW #4H - 9,771 perforated feet tested 823 Bbls/d oil & 2,825
Mcf/d or 1,489 BOE/d (three-stream) on a 26/64" choke
-- Horned Frog NW #5H - 9,645 perforated feet tested 797 Bbls/d oil & 2,872
Mcf/d or 1,475 BOE/d (three-stream) on a 26/64" choke
These wells are our second set at our Horned Frog NW property and immediately offset the Horned Frog NW #2H and #3H, which were placed onstream last year. Early indications are that we have demonstrated two important technical achievements. First, we believe we have demonstrated the Company's capability to maximize lateral length while maintaining productivity per foot (these wells are 50% longer than our first pair). On a per foot basis, the new wells are producing at nearly identical rates compared to the 'parent' wells drilled last year. Additionally, we believe that we have demonstrated our ability to not damage productivity and recovery of the parent wells. After shut-in for fracture stimulation of our new #4H and #5H wells, the #2H and #3H have reestablished rates of production that exceed rates prior to shut-in.
In late April, the Company completed drilling operations on the Horned Frog F #1H and #2H. These wells were drilled to total measured depths of 22,675 and 22,520 feet, respectively, and are expected to have perforated intervals averaging 12,350 feet. Fracture stimulation operations are expected to begin in May with an average proppant concentration exceeding 2,000 pounds per foot. These wells are expected to begin flowback operations on or around July 1. Lonestar holds a 100% WI / 78% NRI in these wells.
EAGLE FORD SHALE TREND- CENTRAL REGION
In our Central Region, 1Q19 production averaged approximately 5,391 BOE per day, a 33% increase over the prior year. On March 22, 2019, we completed the divestiture of our Pirate assets in Wilson County for $12.3 million, before closing adjustments, to a private operator. This asset contributed approximately 200 BOE/d. Despite this sale, the continued growth of the region was largely driven by the Sooner acquisition which occurred in November 2018.
The Company did not place any new wells onstream in the Central Region during the first quarter of 2019 but did complete drilling operations on the Georg #3H, Georg #4H, Georg #5H, and Georg #6H. These wells were drilled to average total measured depths ranging from 16,396 feet and 16,475 feet. Completion operations finished last week. The wells were fracture-stimulated using diverters with an average proppant concentration of 2,000 pounds per foot over 25 stages with average perforated intervals of 7,210 feet. Lonestar has an 80% WI / 61% NRI in these wells.
Completion operations on this four-well pad concluded last week. The wells were fracture-stimulated using diverters with an average proppant concentration of 2,000 pounds per foot over 25 stages. In the past week, these four wells were placed into flowback operations. Perforations and test rates for the for wells are:
-- Georg #3H - 7,156 perforated feet tested 1,129 Bbls/d oil & 693 Mcf/d or
1,290 BOE/d (three-stream) on a 26/64" choke
-- Georg #4H - 7,230 perforated feet tested 1,113 Bbls/d oil & 589 Mcf/d or
1,250 BOE/d (three-stream) on a 25/64" choke
-- Georg #5H - 7,227 perforated feet tested 1,276 Bbls/d oil & 737 Mcf/d or
1,447 BOE/d (three-stream) on a 26/64" choke
-- Georg #6H - 7,236 perforated feet tested 1,294 Bbls/d oil & 783 Mcf/d or
1,476 BOE/d (three-stream) on a 26/64" choke
At the end of the first quarter, the Company commenced drilling 3 gross / 3.0 net wells at its Sooner property, the Buchhorn #4H, Buchhorn #5H and Buchhorn #6H. These wells, our first at Sooner, have planned total measured depths of approximately 20,300 feet and expected perforated intervals of 6,000 feet. Lonestar expects to commence flowback operations on these wells in August 2019. Lonestar has a 100% WI / 78% NRI in these wells.
Lonestar is also currently drilling 2 gross / 2.0 net wells on assets in Fayette County acquired from Sanchez Energy in 2017. These wells, the Five Mile Creek E&B #A1H and the Five Mile Creek E&B #B2H are projected to be the longest laterals drilled by the Company to date, with projected perforated intervals of 13,000 feet.
EAGLE FORD SHALE TREND- EASTERN REGION
In our Eastern Region, production for the first quarter of 2019 averaged approximately 259 BOE per day, a 41% decrease over the prior year. The Company did not complete any wells in this region in the first quarter. However, Lonestar has permitted a horizontal well intended to have a 10,000' perorated interval in western Brazos County. This well is on-strike with its Wildcat B#1H wells, which has produced a cumulative 460,000 BOE in 24 months of production. Lonestar plans to spud the well in June and expects to have a 50% WI / 38% NRI in the well.
CONFERENCE CALL DETAILS
Lonestar will host a live conference call on Monday, May 13, 2019 at 9:00 AM CDT to discuss the first quarter 2019 results and operational highlights.
To access the conference call, participants should dial:
USA: 1-800-925-4693
International: +1-303-223-0113
A playback of the conference call will be available on the Investor Relations section of Company's website beginning approximately May 14, 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 74,253 gross (53,448 net) acres in what we believe to be the formation's crude oil and condensate windows, as of March 31, 2019. 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 filed with the Securities and Exchange Commission, or the SEC, on March 13, 2019, 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)
March 31, December 31,
2019 2018
---
Assets
Current assets
Cash and cash equivalents $
3,767 $
5,355
Accounts receivable
Oil, natural gas liquid and
natural gas sales 16,880 15,103
Joint interest owners and
others, net 3,695 4,541
Related parties 76 301
Derivative financial instruments 3,393 15,841
Prepaid expenses and other 1,933 1,966
Total current assets 29,744 43,107
Property and equipment
Oil and gas properties, using the successful
efforts method of accounting
Proved properties 909,077 960,711
Unproved properties 79,616 81,850
Other property and equipment 20,865 17,727
Less accumulated depreciation,
depletion, amortization and
impairment (346,748) (369,529)
Property and equipment, net 662,810 690,759
Deferred tax asset 552
Derivative financial instruments 1,524 7,302
Other non-current assets 2,357 2,944
Total assets $
696,987 $
744,112
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $
20,113 $
18,260
Accounts payable - related
parties 238 181
Oil, natural gas liquid and
natural gas sales payable 13,549 13,022
Accrued liabilities 19,872 28,128
Derivative financial instruments 16,317 430
Total current liabilities 70,089 60,021
Long-term liabilities
Long-term debt 448,149 436,882
Asset retirement obligations 6,751 7,195
Deferred tax liabilities, net - 12,370
Warrant liability 402 366
Warrant liability - related
parties 755 689
Derivative financial instruments 2,305 21
Other non-current liabilities 3,926 4,021
Total long-term liabilities 462,288 461,544
Commitments and contingencies
Stockholders' Equity
Class A voting common stock,
$0.001 par value, 100,000,000
shares authorized, 24,773,643
and 24,645,825 issued and
outstanding, respectively 142,655 142,655
Series A-1 convertible
participating preferred stock,
$0.001 par value, 93,849 and
91,784 shares issued and
outstanding, respectively -
Additional paid-in capital 175,006 174,379
Accumulated deficit (153,051) (94,487)
Total stockholders' equity 164,610 222,547
Total liabilities and
stockholders' equity $
696,987 $
744,112
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per share data)
Three Months Ended March 31,
2019 2018
---
Revenues
Oil sales $
33,584 $
33,152
Natural gas liquid sales 3,393 1,734
Natural gas sales 3,764 1,806
Total revenues 40,741 36,692
Expenses
Lease operating and gas
gathering 7,710 4,584
Production and ad valorem
taxes 2,291 2,166
Depreciation, depletion and
amortization 17,970 15,425
Loss on sale of oil and gas
properties 32,894
General and administrative 4,379 3,409
Acquisition costs and other (2) 1,568
Total expenses 65,242 27,152
(Loss) income from
operations (24,501) 9,540
Other expense
Interest expense (10,656) (9,258)
Change in fair value of
warrants (102) (152)
Loss on derivative
financial instruments (36,238) (11,156)
Loss on extinguishment of
debt - (8,619)
Total other expense (46,996) (29,185)
Loss before income taxes (71,497) (19,645)
Income tax benefit 12,933 3,109
Net loss (58,564) (16,536)
Preferred stock dividends (2,065) (1,889)
Net loss attributable to
common stockholders $
(60,629) $
(18,425)
Net loss per common share
Basic $(2.45) $
(0.75)
Diluted $(2.45) $
(0.75)
Weighted average common shares outstanding
Basic 24,698,372 24,559,132
Diluted 24,698,372 24,559,132
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
Three Months Ended March 31,
2019 2018
---
Cash flows from operating activities
Net loss $
(58,564) $
(16,536)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Accretion of asset retirement
obligations 79 43
Depreciation, depletion and
amortization 17,891 15,382
Stock-based compensation 533 450
Stock-based payments - (610)
Deferred taxes (12,922) (3,191)
Loss on derivative financial
instruments 36,238 11,156
Settlements of derivative financial
instruments 1,309 (3,116)
Gain on disposal of property and
equipment (17)
Loss on abandoned property and
equipment - 170
Loss on sale of oil and gas
properties 32,894
Non-cash interest expense 699 2,477
Change in fair value of warrants 102 152
Changes in operating assets and liabilities:
Accounts receivable (2,016) (131)
Prepaid expenses and other assets 304 (709)
Accounts payable and accrued
expenses (6,704) 4,310
Net cash provided by operating
activities 9,826 9,847
Cash flows from investing activities
Acquisition of oil and gas
properties (2,352) (1,605)
Development of oil and gas
properties (29,137) (31,523)
Proceeds from sale of oil and gas
properties 12,107
Purchases of other property and
equipment (2,916) (1,348)
Net cash used in investing
activities (22,298) (34,476)
Cash flows from financing activities
Proceeds from borrowings 30,000 264,565
Payments on borrowings (19,116) (240,436)
Net cash provided by financing
activities 10,884 24,129
Net increase in cash and cash
equivalents (1,588) (500)
Cash and cash equivalents,
beginning of the period 5,355 2,538
Cash and cash equivalents, end of
the period $
3,767 $
2,038
Supplemental information:
Cash paid for taxes
$ $
1,147
Cash paid for interest 16,743 3,970
Non-cash investing and financing activities:
Change in asset retirement
obligation $
(522) $
32
Change in liabilities for capital
expenditures 730 406
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 March 31,
($ in thousands) 2019 2018
Net Loss $
(60,629) $
(18,425)
Income tax benefit (12,933) (3,109)
Interest expense (1) 12,721 11,148
Exploration expense 190
Depreciation,
depletion and
amortization 17,970 15,425
EBITDAX (42,681) 5,038
Rig standby expense 107
Stock-based
compensation 929 450
Loss on sale of oil
and gas properties 32,894
Office lease write-
off 1,568
Loss on extinguishment
of debt 8,619
Unrealized loss on
derivative financial
instruments 35,509 7,594
Unrealized loss on
warrants 102 152
Other expense (income) 183 (7)
Adjusted EBITDAX $
27,043 $
23,415
(1) Interest expense also
includes dividends paid
on Series A Preferred
Stock
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 March 31,
($ in thousands) 2019 2018
Loss before income taxes, as
reported $
(71,497) $
(19,645)
Adjustments for special items:
Non-recurring costs 482 7
Loss on extinguishment of debt 8,619
Unrealized hedging loss 35,509 7,594
Lease write-off 1,568
Loss on sale of oil and gas
properties 32,894
Stock based compensation 929 450
Loss before income taxes, as
adjusted (1,683) (1,407)
Income tax benefit, as
adjusted
Deferred (a) 320 223
Net loss excluding certain
items, a non-GAAP measure $
(1,363) $
(1,184)
Preferred stock dividends (2,065) (1,889)
Net loss after preferred
dividends excluding certain
items, a non-GAAP measure $
(3,428) $
(3,073)
Non-GAAP loss per common
share
Basic $
(0.14) $
(0.13)
Diluted $
(0.14) $
(0.13)
Non-GAAP basic shares
outstanding 24,698,372 24,559,132
Non-GAAP diluted shares
outstanding, if dilutive 24,698,372 24,559,132
(a) Effective tax rate for 2019 and
2018 is estimated to be
approximately 19% and 16%,
respectively.
Lonestar Resources US Inc.
Unaudited Operating Results
Three Months Ended
March 31,
In thousands, except per share
and unit data 2019 2018
Operating Results
Net loss attributable to common
stockholders $
(60,629) $
(18,425)
Net loss per common share -
basic (2.45) (0.75)
Net loss per common share -
diluted (2.45) (0.75)
Net cash provided by operating
activities 9,826 9,847
Revenues
Oil $
33,584 $
33,152
NGLs 3,393 1,734
Natural gas 3,764 1,806
Total revenues $
40,741 $
36,692
Total production volumes by
product
Oil (Bbls) 590,096 516,576
NGLs (Bbls) 217,561 86,819
Natural gas (Mcf) 1,295,204 579,152
Total barrels of oil equivalent
(6:1) 1,023,524 699,920
Daily production volumes by
product
Oil (Bbls/d) 6,557 5,740
NGLs (Bbls/d) 2,417 965
Natural gas (Mcf/d) 14,391 6,435
Total barrels of oil equivalent
(BOE/d) 11,372 7,777
Average realized prices
Oil ($ per Bbl) $
56.90 $
64.18
NGLs ($ per Bbl) 15.60 19.97
Natural gas ($ per Mcf) 2.91 3.12
Total oil equivalent, excluding
the effect from commodity
derivatives ($ per BOE) 39.80 52.42
Total oil equivalent, including
the effect from commodity
derivatives ($ per BOE) 39.09 47.34
Operating and other expenses
Lease operating and gas
gathering $
7,710 $
4,584
Production and ad valorem taxes 2,291 2,166
Depreciation, depletion and
amortization 17,970 15,425
General and administrative (1) 4,379 3,409
Interest expense (2) 10,656 9,258
Operating and other expenses per
BOE
Lease operating and gas
gathering $
7.53 $
6.55
Production and ad valorem taxes 2.24 3.09
Depreciation, depletion and
amortization 17.56 22.04
General and administrative 4.28 4.87
Interest expense 10.41 13.23
(1) General and administrative expenses
include stock-based compensation
(2) Interest expense includes
amortization of debt issuance
cost, premiums, and discounts
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SOURCE Lonestar Resources US Inc.
