Lonestar Announces Second Quarter 2018 Financial Results And Provides Operational Update
FORT WORTH, Texas, Aug. 5, 2018 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 June 30, 2018.
HIGHLIGHTS
-- Lonestar reported a record production result with a 98% increase in net
oil and gas production to 11,140 Boe/d during the three months ended
June 30, 2018 ("2Q18"), compared to 5,635 Boe/d for the three months
ended June 30, 2017 ("2Q17"). Production volumes exceeded the high end
of the Company's guidance of 10,000 - 10,500 Boe/d, and were 79% crude
oil and NGL's on an equivalent basis. The increase in production was
attributable to continued excellence in our drilling and completion
program that has seen greater-than-expected well productivity at our
Hawkeye, Horned Frog and Karnes properties in the Eagle Ford Shale.
-- Benefitting from continued outperformance in production results and good
visibility on new well startups, Lonestar issued production guidance of
11,750-12,200 Boe/d for the third quarter of 2018 ("3Q18"). The midpoint
of this guidance represents an 8% sequential increase over 2Q18 results
and is 57% higher than production reported for the three months ended
September 30, 2017 ("3Q17"). It is also important to note that the
forecasted oil mix increases from 57% in 2Q18 to 61% in 3Q18 as Lonestar
begins to bring on the oiliest part of its 2018 drilling program.
Lonestar also issued guidance for 3Q18 Adjusted EBITDAX of $32 to $34
million, which represents a 13% sequential improvement at its midpoint,
and a 63% increase over 3Q17 results.
-- Based on continued outperformance in well results across its portfolio
and that fact that we have outperformed our targeted improvement in debt
metrics, Lonestar has elected to increase its 2018 capital program to
bring 21 gross wells onstream, versus 19 gross wells previously.
Consequently, Lonestar has increased its drilling and completion budget
from a range of $110 - $115 million to a range of $120 - $130 million.
To account for continued outperformance of its 2018 program and the
addition of 2 wells which will contribute for a portion of the fourth
quarter of 2018, Lonestar is again increasing its full-year 2018
production guidance from 10,300-11,000 Boe/d to a range of 10,600-11,200
Boe/d, which equates to a 68% increase over 2017 results.
Commensurately, Lonestar has also increased its 2018 EBITDAX guidance
from a range of $110-$125 million to a range of $115-$130 million, based
on a $60 average WTI oil price for the remainder of 2018.
-- Lonestar reported a net loss attributable to its common stockholders of
$20.7 million, or ($0.84) per weighted average share, during 2Q18
compared to a net loss of $23.5 million, or ($1.07) per weighted average
share during the 2Q17. 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 2Q18 was
$3.5 million, or ($0.14) per common share. Most notable among these
items include: unrealized hedging losses on financial derivatives,
stock-based compensation and non-recurring legal expenses. Please see
Non-GAAP Financial Measures for additional information.
-- Lonestar reported a 131% increase in Adjusted EBITDAX for the three
months ended June 30, 2018 of $29.2 million compared to $12.7 million
for 2Q17, which exceeded our guidance of $27.0 - $29.0 million and is a
Company record. This improvement was driven by a 98% increase in
production and a 5% increase in the Company's oil-equivalent price
realization after the effect of hedging. 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.
-- The visibility provided by a continuous drilling and completion program
provides the Company with the confidence to issue a preliminary 2019
Outlook. Based on a drilling and completion budget of $120-$130 million,
Lonestar sees daily production increasing to a range of 13,000 -14,000
Boe/d in 2019 and Adjusted EBITDAX increasing to a range of $140-$160
million. Importantly, this 2019 program can be executed with a single
rig and can be essentially funded by internally generated cash flow.
Lonestar's Chief Executive Officer, Frank D. Bracken, III, stated, "In the second quarter, we achieved a production increase of 98% and a 131% increase in Adjusted EBITDAX. Our record-setting second quarter results also represent sharp sequential improvements of 43% for production and 25% for Adjusted EBITDAX. Our second quarter results begin to more fully reflect the outstanding drilling results we have generated thus far in 2018 and have generated operating metrics which continue to exceed guidance. Equally important to Lonestar's improved outlook is the considerable progress we have made in improving our debt metrics and liquidity. Since 2Q17, we have reduced Debt / EBITDAX (Last Quarter Annualized) from 5.4x to 2.8x in 2Q18"
Bracken further remarked, "Our momentum in the Eagle Ford Shale continues to build, and our technical, operational and financial achievements are delivering high price realizations, high margins and outstanding returns to our shareholders, giving us the confidence to augment our 2018 drilling and completion program. Not only can the expanded 2018 program be executed with drilling, completion and fracture stimulation equipment currently under contract, but extending that program deeper into 2018 provides seamless transition into our 2019 program. The visibility provided by a continuous drilling and completion program gives us the confidence to issue a preliminary 2019 Outlook, which sees production increasing by 24% over 2018 levels and Adjusted EBITDAX increasing by a similar amount. Importantly, this 2019 program can be executed with a single rig and can be essentially funded by internally generated cash flow."
OPERATIONAL UPDATE
-- Lonestar reported net oil and gas production of 11,140 Boe/d during the
three months ended June 30, 2018, an increase of 98% compared to 5,635
Boe/d during the three months ended June 30, 2017. 2Q18 production
volumes consisted of 6,378 barrels of oil per day (57%), 2,438 barrels
of NGLs per day (22%), and 13,943 Mcf of natural gas per day (21%). The
Company's production mix for the three months ended June 30, 2018 was
79% liquid hydrocarbons.
-- Lonestar's Eagle Ford Shale assets delivered excellent wellhead
realizations in 2Q18. Lonestar's realized wellhead crude oil price was
$68.41 per barrel, which reflects a positive differential of $0.47/bbl
vs. West Texas Intermediate. Lonestar's realized NGL price was $19.88
per barrel in the second quarter of 2018. Lonestar's natural realized
wellhead natural gas price was $2.94 per Mcf, which reflects a positive
differential of $0.11 to the Henry Hub.
-- Lonestar has delivered a significant reduction in cash operating costs
in 2Q18. Total Cash Operating Expenses for the three months ended June
30, 2018 were $20.3 million, which was 48% higher than cash operating
expenses of $13.7 million in the three months ended June 30, 2017. On a
unit-of-production basis, cash operating expenses decreased 25% from
$26.72 per Boe in the three months ended June 30, 2017 to $20.01 per Boe
in the three months ended June 30, 2018
-- Lease Operating Expenses ("LOE") for the three months ended June 30,
2018 were $5.7 million, which was 77% higher than Lease Operating
Expenses of $3.2 million in the three months ended June 30, 2017,
but was outpaced by a 98% increase in production. On a
unit-of-production basis, lease operating expenses decreased 18% to
$5.62 per Boe for the three months ended June 30, 2018. On a
sequential basis, Lonestar reduced lease operating expenses per Boe
by 5% to $5.62. For 2018, the Company expects LOE to be between
$5.60 and $6.50 per Boe, as relatively fixed costs are spread over
substantially larger production volumes.
-- Gathering, Processing & Transportation Expenses ("G,P&T") for the
three months ended June 30, 2018 were $0.8 million, which was 157%
higher than the G,P&T of $0.3 million in the three months ended June
30, 2017, but commensurate with a 183% increase in gas production.
On a unit-of-production basis, G,P&T increased 30% to $0.79 per Boe
for the three months ended June 30, 2018. For 2018, the Company
expects G,P&T expense to average between $0.75 and $0.85 per Boe.
-- Production Taxes for the three months ended June 30, 2018 were $2.8
million, which was 156% higher than production taxes of $1.1 million
in the three months ended June 30, 2017, driven largely by a 164%
increase in wellhead oil and gas revenues. On a unit-of-production
basis, production taxes increased 30% to $2.72 per Boe for the three
months ended June 30, 2018.
-- General & Administrative Expenses, excluding stock-based
compensation of $0.5 million in the three months ended June 30, 2017
and $2.3 million in the three months ended June 30, 2018 ("G&A"),
decreased from $3.1 million to $3.0 million, respectively. On a
unit-of-production basis, G&A per Boe was reduced 51% year over
year, from $6.12 per Boe in 2017 to $2.98 per Boe in 2018. For 2018,
the Company expects G&A to average between $2.80 and $3.00 per Boe.
-- Interest Expense excluding amortization of debt issuance cost,
premiums, and discounts increased year over year from $6.0 million
in the three months ended June 30, 2017 to $8.3 million in 2018.
This was primarily due to a combination of higher stated interest
rates and principal on the new 11.25% Senior Notes versus the 8.75%
Senior Notes that were retired in January 2018. On a
unit-of-production basis, interest per Boe decreased 30% year over
year from $11.64 per Boe in 2017 to $8.15 per Boe in 2018. For 2018,
the Company expects interest expense to average between $8.15 and
$8.75 per Boe.
-- In the second quarter of 2018, Lonestar expanded its Eagle Ford
operations, placing 5.0 gross / 4.4 net wells online, which included its
first wells at Georg in Karnes County (3.0 gross / 2.4 net) and first
wells at its Horned Frog NW property in La Salle County (2.0 gross / 2.0
net). Results at these locations have exceeded third party estimates,
with initial production rates ("IP's") on the Georg wells coming in at
greater than 1,200 Boepd and Horned Frog NW greater than 1,100 Boepd. In
the third quarter, Lonestar plans to increase completion activity,
placing 8.0 gross / 6.8 net wells online. This includes 2.0 gross / 2.0
net wells at Cyclone placed into flowback in July, 3.0 gross / 2.4 net
wells at Georg during the month of August and 3.0 gross / 2.4 net wells
at Culpepper during the month of September.
EAGLE FORD SHALE TREND- WESTERN REGION
Asherton - In July 2018, Lonestar commenced drilling the Asherton #1H and Asherton #3H with planned total measured depths of approximately 17,680 feet. We project that these wells will have perforated intervals of approximately 10,800 feet. Drilling operations are underway and fracture stimulation operations are scheduled for October 2018. 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 June 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 June 30, 2018. The Burns Ranch leasehold is held by production, and Lonestar does not currently plan any drilling activity here as part of its 2018 drilling and completion budget.
Horned Frog - In La Salle County, the Company further expanded its Eagle Ford Shale footprint by completing its first two locations at Horned Frog North West. The Horned Frog North West #2H and #3H commenced flowback operations in June, 2018. Results of these wells have been encouraging and have a substantially higher oil mix (+125% per foot) than the legacy Horned Frog acreage located to the South. The #2H and #3H wells were drilled to measured depths of 17,560 feet and 17,440 feet, respectively and were fracture-stimulated in engineered completions with an average proppant concentration of 2,030 pounds per foot across an average of 25 stages per well utilizing diverters. The Horned Frog NW #2H, which has a perforated interval of 7,489 feet, continues to be choke-managed, and produced at a Max 30-day production rate of 1,110 Boe/d, consisting of 573 barrels of oil per day, 185 barrels of natural gas liquids per day, and 2,113 Mcf/d of natural gas on a 22/64" choke. The Horned Frog NW #3H, which has a perforated interval of 7,331 feet, continues to be choke-managed, and produced at a Max 30-day production rate of 1,050 Boe/d, consisting of 551 barrels of oil per day, 172 barrels of natural gas liquids per day, and 1,964 Mcf/d of natural gas. Both of these wells are outperforming internal projections, particularly with respect to higher-than-expected oil rates. 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 four months and the results continue to outperform projections. After registering Max-30 IP's averaging 2,155 Boe/d, these wells continue to exhibit robust deliverability on a constant choke. During the first 120 days of production, the Horned Frog G #1H has produced cumulative production of 47,820 barrels of oil and 818,390 Mcf of natural gas, or 240,975 barrels of oil equivalent on a three-stream basis, an average of 2,008 Boe/d over its first 120 days of production. Over the same period, the Horned Frog H #1H has produced cumulative production of 44,235 barrels of oil and 753,898 Mcf of natural gas, or 222,171 barrels of oil equivalent on a three-stream basis, an average of 1,865 Boe/d over its first 120 days of production. To date, these are the two highest producing wells through the first 120 days of production in the Company's history and have outperformed third-party projections by 15%.
EAGLE FORD SHALE TREND- CENTRAL REGION
Cyclone - In July 2018, the Company completed drilling operations on the Cyclone DM #13H and Cyclone DM #14H to total measured depths of 20,205 feet and 19,685 feet, respectively. The Cyclone DM #13H and #14H wells were fracture-stimulated in engineered completions with an average proppant concentration of 1,590 pounds per foot over 35 stages and 34 stages, respectively. The Cyclone DM #13H was completed with a perforated interval of 10,056 feet and tested 577 Bbls/d of oil and 329 Mcf/d of natural gas, or 652 Boe/d (three-stream) on a 28/64'' choke. The Cyclone DM #14H was completed with a perforated interval of 9,600 feet and tested 635 Bbls/d of oil and 362 Mcf/d of natural gas, or 718 Boe/d (three-stream) on a 28/64'' choke. 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. In May, these wells were put on artificial lift which actually increased production by an average of 17% vs. the prior 30 day period. The Hawkeye wells have continued to break away from forecast, outperforming third-party projections by 23%. Now online for 180 days, the Hawkeye #1H has produced a cumulative 115,800 barrels of oil and 63,517 Mcf of natural gas, or 130,356 barrels of oil equivalent on a three-stream basis, or an average of 727 Boe/d over its first 180 days of production. Over the same period, the Hawkeye #2H has produced a cumulative 99,335 barrels of oil and 53,615 Mcf of natural gas, or 111,620 barrels of oil equivalent on a three-stream basis, or an average of 617 Boe/d. The Company continues to grow its leasehold position in the Hawkeye area, having recently acquired approximately 976 gross / 976 net acres which is contiguous to our existing leasehold, which can accommodate 7 additional locations. Lonestar plans to drill two laterals on this newly acquired leasehold which are projected to average approximately 8,700' of perforated interval. We expect to place these wells onstream in November, 2018.
Karnes County - In May 2018, Lonestar completed the Georg EF #18H, Georg EF #19H, and Georg EF #20H to an average total measured depth of 15,450 feet. The Georg EF #18H, which has a perforated interval of 5,896 feet, produced at a Max 30-day production rate of 895 Boe/d, consisting of 775 barrels of oil per day, 64 barrels of natural gas liquids per day, and 336 Mcf per day of natural gas. The Georg EF #19H, which has a perforated interval of 6,116 feet, produced at a Max 30-day production rate of 898 Boe/d, consisting of 781 barrels of oil per day, 62 barrels of natural gas liquids per day, and 327 Mcf per day of natural gas. The Georg EF #20H, which has a perforated interval of 5,979 feet, produced at a Max 30-day production rate of 1,052 Boe/d, consisting of 925 barrels of oil per day, 68 barrels of natural gas liquids per day, and 356 Mcf per day of natural gas. Lonestar owns an 80% WI and 61% NRI in these wells. To date, these wells have outperformed the projections of our independent petroleum engineer.
Pirate - In Wilson County, no new wells were completed during the three months ended June 30, 2018. The Pirate leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018.
Current Operations - Lonestar plans to bring six more wells in the Central Region onstream during the third quarter of 2018. In Karnes County, the Georg #24H, Georg #25H, and Georg #26H have total measured depths of 15,450 feet, 15,500 feet and 15,495 feet, respectively. Fracture stimulation operations have been completed and these wells are expected to begin flowback operations in mid-August. Lonestar owns an 80% WI and 61% NRI in these wells. In Gonzales County, the Culpepper #3-2H, Culpepper #3-3H, and Culpepper #4-4H, which were also drilled on leasehold obtained in the Battlecat acquisition, were drilled to total measured depths of 15,380 feet, 15,325 feet and 15,280 feet, respectively. Fracture stimulation is set to begin in August and flowback operations are forecast to begin in mid-September. Lonestar owns an 80% WI and 60% NRI in these wells.
EAGLE FORD SHALE TREND- EASTERN REGION
Brazos & Robertson Counties - In Brazos County, no new wells were completed during the three months ended June 30, 2018. Lonestar is currently discussing drilling one well on our partners leasehold. Lonestar does not currently have drilling activity budgeted here in 2018.
CONFERENCE CALL DETAILS
Lonestar will host a live conference call on Monday, August 6, 2018 at 9:00 AM CDT to discuss the second quarter 2018 results and operational highlights.
To access the conference call, participants should dial:
USA: 877-256-5083
International: +1-303-223-4391
A playback of the conference call will be available on the Investor Relations section of Company's website beginning approximately August 7, 2018. The playback will be available for approximately 2 weeks.
ABOUT 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 in Texas, where we accumulated approximately 80,944 gross (60,037 net) acres in what we believe to be the formation's crude oil and condensate windows, as of June 30, 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 on our Annual Report on Form 10-K filed with the Securities and Exchange Commission, or the SEC, on March 29, 2018 our Quarterly Reports on Form 10-Q filed with the SEC, 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)
June 30, December 31,
2018 2017
---- ----
Assets
Current assets
Cash and cash equivalents $5,460 $2,538
Accounts receivable
Oil, natural gas liquid and
natural gas sales 12,041 12,289
Joint interest owners and
others, net 1,396 794
Related parties 62 162
Derivative financial instruments 145 472
Prepaid expenses and other 1,653 2,365
----- -----
Total current assets 20,757 18,620
------ ------
Property and equipment
Oil and gas properties, using the successful
efforts method of accounting
Proved properties 834,493 750,226
Unproved properties 76,619 78,655
Other property and equipment 16,817 15,763
Less accumulated depletion,
depreciation, amortization (294,049) (259,382)
-------- --------
Net property and equipment 633,880 585,262
------- -------
Other non-current assets 2,086 2,918
----- -----
Total assets $656,723 $606,800
======== ========
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $32,086 $25,901
Accounts payable --related
parties 270 389
Oil, natural gas liquid and
natural gas sales payable 11,254 8,747
Accrued liabilities 31,519 16,583
Derivative financial instruments 27,570 12,336
Total current liabilities 102,699 63,956
------- ------
Long-term liabilities
Long-term debt 337,264 301,155
Asset retirement obligations 5,918 5,649
Deferred tax liabilities, net 106 8,105
Equity warrant liability 1,404 508
Equity warrant liability --
related parties 2,682 963
Derivative financial instruments 22,186 9,802
Other non-current liabilities 4,948 1,316
----- -----
Total long-term liabilities 374,508 327,498
------- -------
Commitments and contingencies
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, 2,500 shares
issued and outstanding - -
Series A-1 convertible
participating preferred stock,
$0.001 par value, 87,789 and
83,968 shares issued and
outstanding, respectively - -
Additional paid-in capital 174,469 174,871
Accumulated deficit (137,608) (102,180)
Total stockholders' equity 179,516 215,346
------- -------
Total liabilities and
stockholders' equity $656,723 $606,800
======== ========
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per share data)
Three Months Ended June 30, Six Months Ended June 30,
2018 2017 2018 2017
---- ---- ---- ----
Revenues
Oil sales $39,707 $15,090 $72,859 $29,580
Natural gas liquid sales 4,410 1,319 6,143 2,989
Natural gas sales 3,735 1,726 5,542 3,182
----- -----
Total revenues 47,852 18,135 84,544 35,751
------ ------ ------ ------
Expenses
Lease operating and gas
gathering 6,490 3,521 11,074 6,477
Production and ad valorem
taxes 2,761 1,077 4,927 2,114
Depreciation, depletion and
amortization 19,464 12,551 35,027 24,693
Loss on sale of oil and gas
properties - 205 1,568 348
Impairment of oil and gas
properties - 27,081 - 27,081
General and administrative 5,305 3,600 8,724 6,281
Acquisition costs and other (3) 2,680 (13) 2,669
--- -----
Total expenses 34,017 50,715 61,307 69,663
------ ------
Income (loss) from
operations 13,835 (32,580) 23,237 (33,912)
------ ------- ------
Other (expense) income
Interest expense (9,298) (8,819) (18,555) (13,851)
Unrealized (loss) gain on
warrants (2,462) 614 (2,615) 2,884
(Loss) gain on derivative
financial instruments (25,498) 5,416 (36,654) 14,162
Loss on extinguishment of
debt - - (8,619) -
--- ---
Total other (expense)
income, net (37,258) (2,789) (66,443) 3,195
------- ------
Loss before income taxes (23,423) (35,369) (43,206) (30,717)
Income tax benefit 4,648 12,208 7,778 10,621
----- ------ -----
Net loss (18,775) (23,161) (35,428) (20,096)
Preferred stock dividends (1,932) (296) (3,821) (296)
------ ----
Net loss attributable to
common stockholders $(20,707) $(23,457) $(39,249) $(20,392)
======== ======== ======== ========
Net loss per common share
Basic $(0.84) $(1.07) $(1.60) $(0.93)
====== ====== ====== ======
Diluted $(0.84) $(1.07) $(1.60) $(0.93)
====== ====== ====== ======
Weighted average common
shares outstanding
Basic 24,599,744 21,822,015 24,598,345 21,822,015
========== ==========
Diluted 24,599,744 21,822,015 24,598,345 21,822,015
========== ========== ========== ==========
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
Three Months Ended June 30, Three Months Ended June 30,
2018 2017 2018 2017
---- ----
Cash flows from operating
activities
Net loss $(18,775) $(23,163) $(35,428) $(20,096)
Adjustments to reconcile net
loss to net cash provided
by operating activities:
Depreciation, depletion and
amortization 19,463 12,551 35,027 24,693
Stock-based compensation 2,263 461 2,713 639
Share-based payments 9 - (601) -
Deferred taxes (4,785) (12,576) (7,999) (10,985)
Loss (gain) on derivative
financial instruments 25,464 (5,416) 36,620 (14,162)
Settlements of derivative
financial instruments (5,560) 1,167 (8,676) 2,682
Impairment of oil and gas
properties - 27,081 - 27,081
Loss on abandoned property
and equipment - - 170 -
Non-cash interest expense 1,067 2,854 3,544 3,434
Unrealized loss (gain) on
warrants 2,463 (613) 2,615 (2,884)
Changes in operating assets
and liabilities:
Accounts receivable (122) 802 (254) (1,308)
Prepaid expenses and other
assets (450) (2,632) (1,159) (3,010)
Accounts payable and accrued
expenses 7,869 3,861 12,179 11,028
Net cash provided by
operating activities 28,906 4,377 38,751 17,112
Cash flows from investing
activities
Acquisition of oil and gas
properties (1,257) (106,615) (2,862) (108,179)
Development of oil and gas
properties (35,238) (18,908) (66,761) (37,750)
Purchases of other property
and equipment (150) (1,509) (1,498) (1,522)
Net cash used in investing
activities (36,645) (127,032) (71,121) (147,451)
Cash flows from financing
activities
Proceeds from borrowings and
related party borrowings 26,178 67,079 290,744 76,079
Payments on borrowings and
related party borrowings (15,017) (17,003) (255,452) (19,503)
Proceeds from sale of
preferred stock - 77,800 - 77,800
Cost to issue equity - - - (1,000)
Payments of debt issuance
costs - (2,537) - (2,537)
--- ------ --- ------
Net cash provided by
financing activities 11,161 125,339 35,292 130,839
Net decrease in cash and
cash equivalents 3,422 2,684 2,922 500
Cash and cash equivalents,
beginning of the period 2,038 3,884 2,538 6,068
Cash and cash equivalents,
end of the period $5,460 $6,568 $5,460 $6,568
Supplemental information:
Cash paid for taxes $ - $2,240 $1,147 $2,240
Cash paid for interest 2,173 9,762 6,143 10,674
Non-cash investing and
financing activities:
Preferred stock issued for
asset acquisition $ - $10,795 $ - $10,795
Cost to issue equity
included in accounts
payable - 1,500 - 1,500
Asset retirement obligation 151 2,323 183 2,235
Increase (decrease) in
liabilities for capital
expenditures 12,019 (4,203) 12,425 1,358
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) and 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 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 loss for each of the periods indicated.
Three Months Ended June 30, Six Months Ended June 30,
($ in thousands) 2018 2017 2018 2017
Net Loss $(20,707) $(23,457) $(39,249) $(20,392)
Income tax benefit (4,648) (12,208) (7,778) (10,621)
Interest expense (1) 11,230 9,115 22,376 14,147
Exploration expense - 205 - 205
Depreciation, depletion and
amortization 19,464 12,551 35,027 24,693
EBITDAX 5,339 (13,794) 10,376 8,032
Non-recurring costs (2) - 3,127 - 3,127
Stock-based compensation 2,281 461 2,731 639
Loss on sale of oil and gas
properties - 205 - 348
Impairment of oil and gas properties - 27,081 - 27,081
Unrealized loss (gain) on derivative
financial instruments 18,896 (3,770) 26,489 (12,109)
Unrealized loss (gain) on warrants 2,462 (613) 2,615 (2,884)
Lease write-off - - 1,568 -
Loss on extinguishment of debt - - 8,619 -
Other expense (income) 232 (46) 226 (50)
Adjusted EBITDAX 29,210 12,651 52,624 24,184
(1) Interest expense also includes dividends paid on Series A Preferred Stock
(2) Non-recurring costs consists of Acquisitions Costs and General and Administrative Expenses related to the re-domiciliation to the United States, and listing on NASDAQ
Adjusted Loss
Adjusted net income 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 comparable to analysts' estimates 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 comparable to analysts' estimates on a diluted per share basis. A table is included which reconciles income or loss from operations to adjusted net income comparable to analysts' estimates and diluted earnings per share (adjusted).
The following table presents a reconciliation of Adjusted Net Income to the GAAP financial measure of net loss for each of the periods indicated.
Lonestar Resources US Inc.
Unaudited Reconciliation of Loss Before Income Taxes As Reported To Loss Before Income Taxes Excluding Certain Items, a non-GAAP measure (Adjusted Loss)
Three Months Ended June 30, Six Months Ended June 30,
2018 2017 2018 2017
---- ---- ---- ----
(In thousands) (In thousands)
Loss before income taxes, as
reported $(23,423) $(35,369) $(43,206) $(30,717)
Adjustments for special items:
Impairment of oil and gas
properties - 27,081 - 27,081
Early payment premium on Second
Lien Notes - 1,050 - 1,050
Warrant discount recognition
due to early payment on Second
Lien Notes - 1,991 - 1,991
Legal expenses for corporate
governance and public
reporting setup - 399 - 399
General & administrative non-
recurring costs 1 205 8 212
Non-recurring legal expense 233 - 233 -
Loss on extinguishment of debt - - 8,619 -
Unrealized hedging (gain) loss 18,896 (3,770) 26,489 (12,109)
Lease write-off - - 1,568 -
Stock based compensation 2,281 461 2,731 639
Advisory fees for completion of
acquisition - 2,726 - 2,726
Loss before income taxes, as
adjusted $(2,012) $(5,226) $(3,558) $(8,728)
Income tax benefit (expense),
as adjusted
Current - - - -
Deferred (a) 415 1,815 735 3,031
Net loss excluding certain
items, a non-GAAP measure $(1,597) $(3,411) $(2,823) $(5,697)
======= ======= =======
Preferred stock dividends (1,932) (296) (3,821) (296)
------ ---- ------ ----
Net loss after preferred
dividends excluding certain
items, a non-GAAP measure $(3,529) $(3,707) $(6,644) $(5,993)
======= ======= =======
Non-GAAP loss per common share
Basic $(0.14) $(0.17) $(0.27) $(0.27)
Diluted $(0.14) $(0.17) $(0.27) $(0.27)
Non-GAAP diluted shares
outstanding, if dilutive 24,559,744 21,822,015 24,598,345 21,822,015
(a) Effective tax rate for 2018 and 2017 is estimated to be approximately 21% and 35%, respectively.
Lonestar Resources US Inc.
Unaudited Operating Results
In thousands, except per share
and unit data Three Months Ended Six Months Ended
June 30, June 30,
---
2018 2017 2018 2017
---- ---- ---- ----
Operating revenues
Oil $39,707 $15,090 $72,859 $29,580
NGLs 4,410 1,319 6,143 2,989
Natural gas 3,735 1,726 5,542 3,182
----- ----- ----- -----
Total operating revenues $47,852 $18,135 $84,544 $35,751
======= ======= ======= =======
Total production volumes by
product
Oil (Bbls) 580,398 324,324 1,097,041 616,848
NGLs (Bbls) 221,858 91,364 308,786 174,846
Natural gas (Mcf) 1,268,813 582,582 1,848,010 1,170,346
Total barrels of oil equivalent
(BOE) 1,013,740 512,785 1,713,708 986,812
Daily production volumes by
product
Oil (Bbls/d) 6,378 3,564 6,061 3,408
NGLs (Bbls/d) 2,438 1,004 1,706 966
Natural gas (Mcf/d) 13,943 6,402 10,210 6,466
Total barrels of oil equivalent
(BOE/d) 11,140 5,635 9,468 5,452
Average realized prices
Oil ($ per Bbl) $68.41 $46.52 $66.41 $47.95
NGLs ($ per Bbl) 19.88 14.43 19.89 17.10
Natural gas ($ per Mcf) 2.94 2.96 3.00 2.72
Total oil equivalent, excluding
the effect from hedging ($ per
BOE) 47.20 35.36 49.33 36.23
Total oil equivalent, including
the effect from hedging ($ per
BOE) 40.69 38.57 43.40 38.31
Operating and other expenses
Lease operating and gas
gathering $6,490 $3,521 $11,074 $6,477
Production and ad valorem taxes 2,761 1,077 4,927 2,114
Depreciation, depletion and
amortization 19,464 12,551 35,027 24,693
General and administrative 5,305 3,600 8,724 6,281
Interest expense 9,298 8,819 18,555 13,851
Operating and other expenses per
BOE
Lease operating and gas
gathering $6.40 $6.87 $6.46 $6.56
Production and ad valorem taxes 2.72 2.10 2.88 2.14
Depreciation, depletion and
amortization 19.20 24.48 20.44 25.02
General and administrative 5.23 7.02 5.09 6.36
Interest expense 9.17 17.20 10.83 14.04
(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.
