Lonestar Announces Third Quarter 2018 Financial Results
And Provides Operational Update
Fort Worth, Texas, November 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 September 30, 2018.
HIGHLIGHTS
• | Lonestar reported record production with a 63% increase in net oil and gas production to 12,471 Boe/d during the three months ended September 30, 2018 (“3Q18”), compared to 7,662 Boe/d for the three months ended September 30, 2017 (“3Q17”). Sequentially, 3Q18 volumes rose 12%. Production volumes exceeded the Company’s guidance of 11,800 - 12,200 Boe/d and were 81% crude oil and NGL’s on an equivalent basis. The increase in production was attributable to the drilling and completion of 8.0 gross / 6.8 net wells during the quarter. |
• | Lonestar reported a net loss attributable to its common stockholders of $21.7 million, or ($0.88) per weighted average share, during 3Q18 compared to a net loss of $8.9 million, or ($0.41) per weighted average share during 3Q17. 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 3Q18 was $0.6 million, or $0.02 per basic common share or $0.01 per dilutive share. Most notable among these items include: the impairment related to lease expirations included in our unproved properties, 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 an 82% increase in Adjusted EBITDAX for the three months ended September 30, 2018 of $37.0 million compared to $20.3 million for 3Q17, which exceeded our guidance of $32.0 - $34.0 million and sets another record for the Company. This improvement was driven by a 63% increase in production and an 8% 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. |
• | Lonestar’s production guidance sees continued volume growth to 12,600-12,800 Boe/d for the fourth quarter of 2018 (”4Q18”). While total production volume growth will slow in 4Q18 due to a combination of a slower rate of completions and shut-in oil volumes due to Frio River flooding, Lonestar sees crude oil production increasing from 7,183 bbl/d in 3Q18 to 7,700-8,000 bbl/d in |
4Q18, equating to sequential growth of roughly 10%. The midpoint of this guidance represents a 76% increase over rates produced in the three months ended December 31, 2017 (“4Q17”). Lonestar also issued guidance for 4Q18 Adjusted EBITDAX of $39 to $41 million, which represents a 10% sequential improvement at its midpoint, and a 100% increase over 4Q17 results.
• | Lonestar continues to use commodity derivatives to create a higher degree of certainty to our cash flows and returns while mitigating financial risk. During 3Q18, Lonestar added an additional 1,000 Bo/d for 2019 and 1,000 Bo/d for 2020 at an average weighted price of $67.39/bbl and $63.61/bbl, respectively. Additionally, Lonestar executed LLS/WTI basis swaps which match the volumes of the Company’s WTI swaps at an average weighted price of $5.05/bbl for 2019. By locking in these swaps, it should allow the Company to realize a premium to WTI after marketing, regardless of market conditions. |
Lonestar’s Chief Executive Officer, Frank D. Bracken, III, stated, “In the third quarter, we achieved a production increase of 63% and an 82% increase in Adjusted EBITDAX. Our record-setting third quarter results also represent sequential improvements of 12% for production and 8% for Adjusted EBITDAX. Based on continued execution of our Geo-Engineered completion design and continued timely delivery of new well startups, our financial results continue to exceed our guidance. Lonestar is also making substantial progress on a key objective of improving our debt metrics and liquidity. Since 1Q18, we have reduced Debt / EBITDAX from 3.4x to 2.5x in 3Q18.”
Bracken further remarked, “Our momentum in the Eagle Ford Shale continues to build, and our technical, operational and financial achievements are delivering premium price realizations, expanded operating margins and outstanding returns to our shareholders. Our strategy of acquiring “bolt-on” leasehold in our core areas accelerated in the third quarter and delivered significant value. In 3Q18, we entered into agreements to acquire approximately 3,000 acres at a total cost of $3.0 million. This acreage, which was strategically acquired on tracts that are contiguous to Lonestar’s existing leasehold in Karnes and Gonzales Counties, increase the lengths of 41 of our drilling locations by an average of 42%, and bolster the Company’s inventory of laterals which exceed 10,000 feet. Year-to-date, Lonestar has acquired approximately 4,000 net acres in our core areas which we estimate add 8.2 MMBOE of net reserves and approximately $90 million of PV-10, organically replacing more than 200% of our estimated 2018 annual production.”
Bracken concluded, “2018 has proven to be a breakout year for Lonestar shareholders. In aggregate, our new wells have delivered production that exceed our third-party type curves and confirm exceptional returns in our core development areas (Horned Frog, Cyclone/Hawkeye and Karnes County). Our contracted drilling rigs and dedicated frac spread have allowed Lonestar to deliver these exceptional well results on-budget and ahead of schedule, which has established our Company as one that can consistently deliver impressive results to our shareholders. We remain highly confident in our 2019 outlook, which calls for production of 13,000-14,000 boe/d (a 23% increase at the midpoint) and Adjusted EBITDAX of $140-$160 million (a 20% increase at the midpoint).”
OPERATIONAL UPDATE
• | Lonestar reported net oil and gas production of 12,471 Boe/d during the three months ended September 30, 2018, an increase of 63% compared to 7,662 Boe/d during the three months ended September 30, 2017. 3Q18 production volumes consisted of 7,183 barrels of oil per day (58%), 2,855 barrels of NGLs per day (23%), and 14,600 Mcf of natural gas per day (19%). The Company’s |
production mix for the three months ended September 30, 2018 was 81% liquid hydrocarbons. The Company exceeded production guidance in spite of shut-ins of 250 boe/d at Burns Ranch in the month of September, which was caused by flood conditions on the Frio River.
• | Lonestar’s Eagle Ford Shale assets delivered excellent wellhead realizations in 3Q18. Lonestar’s realized wellhead crude oil price was $72.40 per barrel, which reflects a positive differential of $2.90/bbl vs. West Texas Intermediate. Lonestar’s realized NGL price was $25.87 per barrel, which at 37% of WTI, was the highest percentage realization since 4Q17. Lonestar’s natural realized wellhead natural gas price was $3.05 per Mcf, which reflects a $0.15/Mcf premium to Henry Hub. |
• | Lonestar delivered a 25% reduction in cash operating costs (outlined below) in 3Q18. 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 September 30, 2018 were $22.7 million, which was 67 % higher than cash expenses of $13.6 million in the three months ended September 30, 2017. However, on a unit-of-production basis, cash expenses decreased 25% from $26.72 per Boe in the three months ended September 30, 2017 to $20.01 per Boe in the three months ended September 30, 2018. |
• | Lease Operating Expenses (“LOE”) for the three months ended September 30, 2018 were $5.9 million, which was 46% higher than LOE of $4.1 million in the three months ended September 30, 2017 but was outpaced by a 63% increase in production. On a unit-of-production basis, lease operating expenses decreased 9% to $5.14 per Boe for the three months ended September 30, 2018. On a sequential basis, Lonestar reduced lease operating expenses per Boe by 5% to $5.14 per Boe. For 4Q18, the Company expects lease operating expense to average between $5.00 and $5.75 per Boe. |
• | Gathering, Processing & Transportation Expenses (“G, P&T”) for the three months ended September 30, 2018 were $0.8 million, which was 50% higher than the G, P&T of $0.5 million in the three months ended September 30, 2017, commensurate with a 105% increase in gas production. On a unit-of-production basis, G, P&T decreased 8% to $0.69 per Boe for the three months ended September 30, 2018. For 4Q18, the Company expects G, P&T expense to average between $0.75 and $0.85 per Boe. |
• | Production Taxes for the three months ended September 30, 2018 were $3.2 million, which was 109% higher than production taxes of $1.5 million in the three months ended September 30, 2017, driven largely by a 118% increase in wellhead oil and gas revenues. On a unit-of-production basis, production taxes increased 28% to $2.80 per Boe for the three months ended September 30, 2018. |
• | General & Administrative Expenses, excluding stock-based compensation of $0.3 million in the three months ended September 30, 2017 and $0.9 million in the three months ended September 30, 2018 (“G&A”), increased from $2.5 million to $3.6 million, respectively. On a unit-of-production basis, G&A per Boe was reduced 11% year over year, from $3.51 per Boe in 2017 to $3.13 per Boe in 2018. For 4Q18, 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 $5.0 million in the three months ended September 30, 2017 to $9.2 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 increased 12% year over year from $7.14 per Boe in 2017 to $8.00 per Boe in 2018, owing to a higher coupon on our Senior Unsecured Notes. For 2018, the Company expects interest expense to average between $8.15 and $8.75 per Boe.
• | In the third quarter of 2018, Lonestar aggressively expanded its Eagle Ford producing well count, placing 8.0 gross / 6.8 net wells online, which included 3.0 gross / 2.4 net wells in Karnes County and 5.0 / 4.4 net wells in Gonzales County. Lonestar expects to continue to grow production organically during the fourth quarter, as it anticipates placing 4.0 gross / 3.3 net wells online during 4Q18. This includes 2.0 gross / 2.0 net wells at Asherton placed into flowback in October, and 2.0 gross / 1.3 net wells at Hawkeye scheduled to begin flowback operations in mid-December. |
EAGLE FORD SHALE TREND- WESTERN REGION
Asherton – In October 2018, the Company completed drilling operations on the Asherton #1HN and Asherton #3HN to total measured depths of 17,725 feet and 17,730 feet, respectively. The Asherton #1HN and #3HN wells were fracture-stimulated in engineered completions using diverters with an average proppant concentration of 1,985 pounds per foot over 37 stages and 36 stages, respectively. On average, these wells were completed with a perforated interval of 10,788 feet and tested 1,053 Boe/d (three stream) on a 32/64’’ choke. The Asherton #1HN was completed with a perforated interval of 10,780 feet and tested 962 Bbls/d of oil and 1,202 Mcf/d of natural gas, or 1,237 Boe/d (three-stream) on a 32/64’’ choke. The Asherton #3HN, which immediately offsets wells that have produced for 4 years, was completed with a perforated interval of 10,795 feet and tested 673 Bbls/d of oil and 1,254 Mcf/d of natural gas, or 960 Boe/d (three-stream) on a 32/64’’ choke. Lonestar owns a 99% working interest (“WI”) and 75% Net Revenue Interest (“NRI”) in these two wells.
Beall Ranch – In Dimmit County, no new wells were completed during the three months ended September 30, 2018. The Beall Ranch leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018.
Burns Ranch Area – In La Salle County, no new wells were completed during the three months ended September 30, 2018. Lonestar is currently mobilizing a drilling rig to Burns Ranch to drill three laterals. These wells are expected to begin flowback operations in February 2019. Lonestar owns a 100% WI and 75% NRI in these wells.
Horned Frog – Lonestar has drilled its first four wells utilizing its Geo-Engineered completion design during 2018. In June, the Company began flowback operations on the Horned Frog NW #2H and Horned Frog NW #3H. These wells, which reached peak rate in July, have now been producing for in excess of four months and the results continue to be encouraging. Through the first 120 days, the Horned Frog NW #2H has produced a cumulative 58,000 barrels of oil and 253,000 Mcf of natural gas, or 118,000 barrels of oil equivalent on a three-stream basis. Over the same period, the Horned Frog NW #3H has produced a cumulative 56,000 barrels of oil and 241,000 Mcf of natural gas, or 113,000 barrels of oil equivalent on a three-stream basis. The Horned Frog NW wells have continued to exceed forecast, outperforming third-party projections by 11%. Lonestar holds a 100% WI and 75% NRI in these wells and has an additional 5 drilling locations offsetting these wells.
Lonestar owns a 100% WI in the Horned Frog G #1H and Horned Frog H #1H, which were placed onstream in March 2018. These wells have now been producing for in excess of seven months and the results continue to outperform projections. During the first 210 days of production, the Horned Frog
G #1H has produced cumulative production of 72,000 barrels of oil and 1,317,000 Mcf of natural gas, or 385,000 barrels of oil equivalent on a three-stream basis, an average of 1,832 Boe/d over its first 210 days of production. Over the same period, the Horned Frog H #1H has produced cumulative production of 67,000 barrels of oil and 1,230,000 Mcf of natural gas, or 359,000 barrels of oil equivalent on a three-stream basis, an average of 1,708 Boe/d over its first 210 days of production. Through their first seven months, these have outperformed third-party projections by 15%, the majority of which has been comprised of crude oil contribution.
EAGLE FORD SHALE TREND- CENTRAL REGION
Cyclone – In July 2018, Lonestar completed the Cyclone DM #13H and Cyclone DM #14H to measured depths of 20,205 feet and 19,685 feet, respectively. As seismic indicated a potential fault, the Cyclone DM #13H well was steered higher within the Lower Eagle Ford shale, out of our target window for approximately 47% of the wells producing lateral. The Cyclone DM #13H has a perforated interval of 10,056 feet and produced at a Max 30-day production rate of 500 Boe/d, consisting of 443 barrels of oil per day, 26 barrels of natural gas liquids per day, and 186 Mcf per day of natural gas. The Cyclone DM #14H, drilled subsequently, was drilled lower in section in the Lower Eagle Ford in our target zone and has a perforated interval of 9,600 feet. The #14H produced at a Max 30-day production rate of 649 Boe/d, consisting of 578 barrels of oil per day, 32 barrels of natural gas liquids per day, and 233 Mcf per day of natural gas. Lonestar owns a 100% WI and 78.5% NRI in these wells.
Hawkeye – Lonestar owns an 87.5% WI in the Hawkeye #1H and Hawkeye #2H, which were placed onstream in January 2018. The Hawkeye wells have continued to deliver exceptional productivity, with oil production outperforming third-party projections by 24%. Now online in excess of nine months, the Hawkeye #1H has produced a cumulative 151,000 barrels of oil and 82,000 Mcf of natural gas, or 170,000 barrels of oil equivalent on a three-stream basis. Over the same period, the Hawkeye #2H has produced a cumulative 128,000 barrels of oil and 72,000 Mcf of natural gas, or 137,000 barrels of oil equivalent on a three-stream basis.
In October 2018, the Company completed drilling operations on the Hawkeye #24H and Hawkeye #25H to total measured depths of 20,050 feet and 17,919 feet, respectively. These wells are projected to average approximately 10,200’ of perforated interval with an average proppant concentration of 1,500 pounds per foot. Fracture stimulation is set to begin in November and flowback operations are forecast to begin in mid-December. Lonestar owns a 65% WI and 50% NRI in these wells.
Karnes County – During the third quarter of 2018, Lonestar drilled and completed 3.0 gross / 2.4 net wells in Karnes County. The Georg #24H, #25H & #26H were drilled to an average total measured depth of 15,480 feet and began flowback operations in August 2018. These wells were fracture-stimulated in engineered completions with an average proppant concentration of 1,980 pounds per foot over 20 stages per well and utilized diverters. The Georg #24H was completed with a perforated interval of 5,910 feet and produced at a Max 30-day production rate of 815 Boe/d, consisting of 708 barrels of oil per day, 57 barrels of natural gas liquids per day, and 300 Mcf/d of natural gas on a 26/64” choke. The Georg #25H was completed with a perforated interval of 6,115 feet and produced at a Max 30-day production rate of 837 Boe/d, consisting of 734 barrels of oil per day, 55 barrels of natural gas liquids per day, and 288 Mcf/d of natural gas on a 26/64” choke. The Georg #26H was completed with a perforated interval of 5,979 feet and produced at a Max 30-day production rate of 949 Boe/d, consisting of 825 barrels of oil per day, 66 barrels of natural gas liquids per day, and 348 Mcf/d of natural gas on
a 26/64” choke. Lonestar owns an 80% WI and 61% NRI in these wells. Lonestar’s first Karnes County wells (the Georg EF #18H, #19H, and #20H), which were completed in May have now produced for four months. On average, these wells have produced a cumulative 78,000 barrels of oil and 64,000 Mcf of natural gas, or 92,900 barrels of oil equivalent on a three-stream basis.
Gonzales County- Lonestar drilled the Culpepper #3-2H, Culpepper #3-3H, and Culpepper #4-4H to an average total measured depth of 15,328 feet and began flowback operations in August 2018. These wells were fracture-stimulated in engineered completions with an average proppant concentration of 2,050 pounds per foot over 19 stages per well and utilized diverters. The Culpepper #3-2H was completed with a perforated interval of 5,337 feet and produced at a Max 30-day production rate of 689 Boe/d, consisting of 607 barrels of oil per day, 44 barrels of natural gas liquids per day, and 230 Mcf/d of natural gas on a 28/64” choke. The Culpepper #3-3H was completed with a perforated interval of 5,245 feet and produced at a Max 30-day production rate of 577 Boe/d, consisting of 508 barrels of oil per day, 37 barrels of natural gas liquids per day, and 193 Mcf/d of natural gas on a 28/64” choke. The Culpepper #3-4H was completed with a perforated interval of 5,383 feet and produced at a Max 30-day production rate of 640 Boe/d, consisting of 560 barrels of oil per day, 43 barrels of natural gas liquids per day, and 226 Mcf/d of natural gas on a 28/64” choke. Lonestar owns an 80% WI and 60% NRI in these wells.
Pirate – In Wilson County, no new wells were completed during the three months ended September 30, 2018. The Pirate leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018.
EAGLE FORD SHALE TREND- EASTERN REGION
Brazos & Robertson Counties – In Brazos County, no new wells were completed during the three months ended September 30, 2018. Lonestar has identified a drilling location and the Company and its partner are aiming to commence drilling operations in the first quarter of 2019.
CONFERENCE CALL DETAILS
Lonestar will host a live conference call on Tuesday, November 6, 2018 at 9:00 AM CDT to discuss the third quarter 2018 results and operational highlights.
To access the conference call, participants should dial:
USA: 800-619-2686
International: +1-303-223-2690
A playback of the conference call will be available on the Investor Relations section of Company’s website beginning approximately November 6, 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 82,154 gross (60,862 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of September 30, 2018. 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, our Quarterly Reports on Form 10-Q/A 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.
As previously disclosed, and as identified in the following financial statements, we restated the unaudited condensed consolidated statements of operations and unaudited condensed consolidated statements of cash flows for the three and nine months ended September 30, 2017.
(Financial Statements to Follow)
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
September 30, 2018 | December 31, 2017 | ||||||||
Assets | |||||||||
Current assets | |||||||||
Cash and cash equivalents | $ | 4,542 | $ | 2,538 | |||||
Accounts receivable | |||||||||
Oil, natural gas liquid and natural gas sales | 14,936 | 12,289 | |||||||
Joint interest owners and others, net | 2,722 | 794 | |||||||
Related parties | 184 | 162 | |||||||
Derivative financial instruments | 28 | 472 | |||||||
Prepaid expenses and other | 2,216 | 2,365 | |||||||
Total current assets | 24,628 | 18,620 | |||||||
Property and equipment | |||||||||
Oil and gas properties, using the successful efforts method of accounting | |||||||||
Proved properties | 895,983 | 750,226 | |||||||
Unproved properties | 77,561 | 78,655 | |||||||
Other property and equipment | 16,951 | 15,763 | |||||||
Less accumulated depreciation, depletion, amortization and impairment | (346,078 | ) | (274,374 | ) | |||||
Property and equipment, net | 644,417 | 570,270 | |||||||
Deferred tax assets, net | 2,376 | — | |||||||
Derivative financial instruments | 288 | — | |||||||
Other non-current assets | 1,554 | 2,918 | |||||||
Total assets | $ | 673,263 | $ | 591,808 | |||||
Liabilities and Stockholders' Equity | |||||||||
Current liabilities | |||||||||
Accounts payable | $ | 33,126 | $ | 25,901 | |||||
Accounts payable -- related parties | 284 | 389 | |||||||
Oil, natural gas liquid and natural gas sales payable | 13,705 | 8,747 | |||||||
Accrued liabilities | 27,130 | 16,583 | |||||||
Derivative financial instruments | 42,558 | 12,336 | |||||||
Total current liabilities | 116,803 | 63,956 | |||||||
Long-term liabilities | |||||||||
Long-term debt | 377,617 | 301,155 | |||||||
Asset retirement obligations | 6,002 | 5,649 | |||||||
Deferred tax liabilities, net | — | 4,769 | |||||||
Equity warrant liability | 1,231 | 508 | |||||||
Equity warrant liability -- related parties | 2,345 | 963 | |||||||
Derivative financial instruments | 17,954 | 9,802 | |||||||
Other non-current liabilities | 5,873 | 1,316 | |||||||
Total long-term liabilities | 411,022 | 324,162 | |||||||
Commitments and contingencies (Note 12) | |||||||||
Stockholders' Equity | |||||||||
Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 24,637,127 and 24,506,647 issued and outstanding, respectively | 142,655 | 142,655 | |||||||
Class B non-voting common stock, $0.001 par value, 5,000 shares authorized, 0 and 10,000 shares issued and outstanding, respectively | — | — | |||||||
Series A-1 convertible participating preferred stock, $0.001 par value, 89,764 and 83,968 shares issued and outstanding, respectively | — | — | |||||||
Additional paid-in capital | 174,459 | 174,871 | |||||||
Accumulated deficit | (171,676 | ) | (113,836 | ) | |||||
Total stockholders' equity | 145,438 | 203,690 | |||||||
Total liabilities and stockholders' equity | $ | 673,263 | $ | 591,808 | |||||
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per share data)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||||
(Restated) | (Restated) | |||||||||||||||||
Revenues | ||||||||||||||||||
Oil sales | $ | 47,846 | $ | 23,162 | $ | 120,705 | $ | 52,742 | ||||||||||
Natural gas liquid sales | 6,795 | 1,831 | 12,939 | 4,820 | ||||||||||||||
Natural gas sales | 4,096 | 1,890 | 9,637 | 5,072 | ||||||||||||||
Total revenues | 58,737 | 26,883 | 143,281 | 62,634 | ||||||||||||||
Expenses | ||||||||||||||||||
Lease operating and gas gathering | 6,687 | 4,576 | 17,761 | 11,053 | ||||||||||||||
Production and ad valorem taxes | 3,218 | 1,541 | 8,145 | 3,656 | ||||||||||||||
Depreciation, depletion and amortization | 23,775 | 16,530 | 59,937 | 42,003 | ||||||||||||||
Loss on sale of oil and gas properties | — | 119 | 1,568 | 466 | ||||||||||||||
Impairment of oil and gas properties | 12,169 | — | 12,169 | 27,081 | ||||||||||||||
General and administrative | 4,661 | 2,644 | 13,385 | 8,925 | ||||||||||||||
Acquisition costs and other | 315 | 333 | 302 | 3,001 | ||||||||||||||
Total expenses | 50,825 | 25,743 | 113,267 | 96,185 | ||||||||||||||
Income (loss) from operations | 7,912 | 1,140 | 30,014 | (33,551 | ) | |||||||||||||
Other (expense) income | ||||||||||||||||||
Interest expense | (10,215 | ) | (5,965 | ) | (28,771 | ) | (19,816 | ) | ||||||||||
Unrealized (loss) gain on warrants | 509 | 402 | (2,105 | ) | 3,286 | |||||||||||||
(Loss) gain on derivative financial instruments | (18,198 | ) | (7,657 | ) | (54,852 | ) | 6,505 | |||||||||||
Loss on extinguishment of debt | — | — | (8,619 | ) | — | |||||||||||||
Total other expense, net | (27,904 | ) | (13,220 | ) | (94,347 | ) | (10,025 | ) | ||||||||||
Loss before income taxes | (19,992 | ) | (12,080 | ) | (64,333 | ) | (43,576 | ) | ||||||||||
Income tax benefit | 282 | 4,956 | 6,493 | 15,854 | ||||||||||||||
Net loss | (19,710 | ) | (7,124 | ) | (57,840 | ) | (27,722 | ) | ||||||||||
Preferred stock dividends | (1,975 | ) | (1,824 | ) | (5,796 | ) | (2,120 | ) | ||||||||||
Net loss attributable to common stockholders | $ | (21,685 | ) | $ | (8,948 | ) | $ | (63,636 | ) | $ | (29,842 | ) | ||||||
Net loss per common share | ||||||||||||||||||
Basic | $ | (0.88 | ) | $ | (0.41 | ) | $ | (2.59 | ) | $ | (1.37 | ) | ||||||
Diluted | $ | (0.88 | ) | $ | (0.41 | ) | $ | (2.59 | ) | $ | (1.37 | ) | ||||||
Weighted average common shares outstanding | ||||||||||||||||||
Basic | 24,599,744 | 21,822,015 | 24,598,816 | 21,822,015 | ||||||||||||||
Diluted | 24,599,744 | 21,822,015 | 24,598,816 | 21,822,015 | ||||||||||||||
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||||||
(Restated) | (Restated) | ||||||||||||||||||
Cash flows from operating activities | |||||||||||||||||||
Net loss | $ | (19,710 | ) | $ | (7,124 | ) | $ | (57,840 | ) | $ | (27,722 | ) | |||||||
Adjustments to reconcile net loss to net cash provided by operating activities: | |||||||||||||||||||
Depreciation, depletion and amortization | 23,775 | 16,530 | 59,937 | 42,003 | |||||||||||||||
Stock-based compensation | 924 | 346 | 3,637 | 985 | |||||||||||||||
Share-based payments | — | — | (601 | ) | — | ||||||||||||||
Deferred taxes | (714 | ) | (4,867 | ) | (7,145 | ) | (16,116 | ) | |||||||||||
Loss (gain) on derivative financial instruments | 18,198 | 7,657 | 54,852 | (6,505 | ) | ||||||||||||||
Settlements of derivative financial instruments | (7,647 | ) | 2,212 | (16,323 | ) | 4,894 | |||||||||||||
Impairment of oil and gas properties | 12,169 | — | 12,169 | 27,081 | |||||||||||||||
Loss on abandoned property and equipment | — | — | 171 | — | |||||||||||||||
Non-cash interest expense | 1,013 | 940 | 4,556 | 4,375 | |||||||||||||||
Unrealized loss (gain) on warrants | (509 | ) | (402 | ) | 2,105 | (3,286 | ) | ||||||||||||
Changes in operating assets and liabilities: | |||||||||||||||||||
Accounts receivable | (4,343 | ) | (3,906 | ) | (4,596 | ) | (5,214 | ) | |||||||||||
Prepaid expenses and other assets | (676 | ) | (576 | ) | (1,835 | ) | (3,559 | ) | |||||||||||
Accounts payable and accrued expenses | (5,410 | ) | (2,542 | ) | 6,733 | 11,531 | |||||||||||||
Net cash provided by operating activities | 17,070 | 8,268 | 55,820 | 28,467 | |||||||||||||||
Cash flows from investing activities | |||||||||||||||||||
Acquisition of oil and gas properties | (1,900 | ) | (853 | ) | (4,762 | ) | (109,031 | ) | |||||||||||
Development of oil and gas properties | (55,931 | ) | (19,167 | ) | (122,691 | ) | (56,918 | ) | |||||||||||
Purchases of other property and equipment | (133 | ) | (10,058 | ) | (1,631 | ) | (11,580 | ) | |||||||||||
Net cash used in investing activities | (57,964 | ) | (30,078 | ) | (129,084 | ) | (177,529 | ) | |||||||||||
Cash flows from financing activities | |||||||||||||||||||
Proceeds from borrowings and related party borrowings | 58,000 | 26,909 | 348,744 | 102,988 | |||||||||||||||
Payments on borrowings and related party borrowings | (18,014 | ) | (8,004 | ) | (273,466 | ) | (27,507 | ) | |||||||||||
Proceeds from sale of preferred stock | — | — | — | 77,800 | |||||||||||||||
Repurchase and retire Class B Common Stock | (10 | ) | — | (10 | ) | — | |||||||||||||
Cost to issue equity | — | 1,297 | — | (2,790 | ) | ||||||||||||||
Payments of debt issuance costs | — | (148 | ) | — | (2,685 | ) | |||||||||||||
Net cash provided by financing activities | 39,976 | 20,054 | 75,268 | 147,806 | |||||||||||||||
Net decrease in cash and cash equivalents | (918 | ) | (1,756 | ) | 2,004 | (1,256 | ) | ||||||||||||
Cash and cash equivalents, beginning of the period | 5,460 | 6,568 | 2,538 | 6,068 | |||||||||||||||
Cash and cash equivalents, end of the period | $ | 4,542 | $ | 4,812 | $ | 4,542 | $ | 4,812 | |||||||||||
Supplemental information: | |||||||||||||||||||
Cash paid for taxes | $ | — | $ | 225 | $ | 1,147 | $ | 2,465 | |||||||||||
Cash paid for interest | 16,181 | 386 | 22,324 | 11,060 | |||||||||||||||
Non-cash investing and financing activities: | |||||||||||||||||||
Preferred stock issued for asset acquisition | — | 10,795 | — | 10,795 | |||||||||||||||
Increase in asset retirement obligation | 39 | 83 | 222 | 2,318 | |||||||||||||||
Increase in liabilities for capital expenditures | 4,563 | 312 | 16,988 | 1,670 | |||||||||||||||
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 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 September 30, | Nine Months Ended September 30, | |||||||||||||||||||
($ in thousands) | 2018 | 2017 | 2018 | 2017 | ||||||||||||||||
(Restated) | (Restated) | |||||||||||||||||||
Net loss attributable to common shareholders | $ | (21,685 | ) | $ | (8,948 | ) | $ | (63,636 | ) | $ | (29,842 | ) | ||||||||
Income tax (benefit) expense | (282) | (4,956 | ) | (6,493 | ) | (15,854 | ) | |||||||||||||
Interest expense (1) | 12,190 | 7,789 | 34,567 | 21,936 | ||||||||||||||||
Exploration expense | 109 | — | 109 | 205 | ||||||||||||||||
Depreciation, depletion and amortization | 23,775 | 16,530 | 59,937 | 42,003 | ||||||||||||||||
EBITDAX | $ | 14,107 | $ | 10,415 | $ | 24,484 | $ | 18,448 | ||||||||||||
Rig standby expense | 27 | 61 | 27 | 61 | ||||||||||||||||
Non-recurring costs (2) | 60 | 337 | 60 | 3,464 | ||||||||||||||||
Stock-based compensation | 924 | 346 | 3,637 | 985 | ||||||||||||||||
Loss on sale of oil and gas properties | — | 119 | — | 466 | ||||||||||||||||
Impairment of oil and gas properties | 12,169 | — | 12,169 | 27,081 | ||||||||||||||||
Unrealized loss (gain) on derivative financial instruments | 9,911 | 9,437 | 36,401 | (2,672 | ) | |||||||||||||||
Unrealized loss (gain) on warrants | (509) | (402 | ) | 2,105 | (3,286 | ) | ||||||||||||||
Lease write-off | — | — | 1,568 | — | ||||||||||||||||
Loss on extinguishment of debt | — | — | 8,619 | — | ||||||||||||||||
Other expense (income) | 315 | (4 | ) | 540 | (53 | ) | ||||||||||||||
Adjusted EBITDAX | $ | 37,004 | $ | 20,309 | $ | 89,610 | $ | 44,494 | ||||||||||||
1 Interest expense also includes dividends paid on Series A Preferred Stock
2 Non-recurring costs consists of Acquisitions Costs.
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 net loss before taxes 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 before taxes 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 September 30, | Nine Months Ended September 30, | |||||||||||||||||||||
In thousands, except per share and unit data | 2018 | 2017 | 2018 | 2017 | ||||||||||||||||||
(Restated) | (Restated) | |||||||||||||||||||||
Loss before income taxes, as reported | $ | (19,992 | ) | $ | (12,080 | ) | $ | (64,333 | ) | $ | (43,576 | ) | ||||||||||
Adjustments for special items: | ||||||||||||||||||||||
Impairment of oil and gas properties | 12,169 | — | 12,169 | 27,081 | ||||||||||||||||||
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 | — | — | — | 399 | ||||||||||||||||||
General & administrative non-recurring costs | 168 | 337 | 176 | 549 | ||||||||||||||||||
Rig standby expense | 27 | 61 | 27 | 61 | ||||||||||||||||||
Non-recurring legal expense | — | — | 233 | — | ||||||||||||||||||
Loss on extinguishment of debt | — | — | 8,619 | — | ||||||||||||||||||
Unrealized hedging (gain) loss | 9,911 | 9,437 | 36,401 | (2,672 | ) | |||||||||||||||||
Lease write-off | — | — | 1,568 | — | ||||||||||||||||||
Stock based compensation | 924 | 346 | 3,637 | 985 | ||||||||||||||||||
Advisory fees for completion of acquisition | — | — | — | 2,726 | ||||||||||||||||||
Income (loss) before income taxes, as adjusted | $ | 3,207 | $ | (1,899 | ) | $ | (1,503 | ) | $ | (11,406 | ) | |||||||||||
Income tax benefit (expense), as adjusted | ||||||||||||||||||||||
Current | — | — | — | — | ||||||||||||||||||
Deferred (a) | (655 | ) | 697 | 307 | 4,187 | |||||||||||||||||
Net income (loss) excluding certain items, a non-GAAP measure | $ | 2,552 | $ | (1,202 | ) | $ | (1,196 | ) | $ | (7,219 | ) | |||||||||||
Preferred stock dividends | (1,975 | ) | (1,824 | ) | (5,796 | ) | (2,120 | ) | ||||||||||||||
Net income (loss) after preferred dividends excluding certain items, a non-GAAP measure | $ | 577 | $ | (3,026 | ) | $ | (6,992 | ) | $ | (9,339 | ) | |||||||||||
Non-GAAP loss per common share | ||||||||||||||||||||||
Basic | $ | 0.02 | $ | (0.14 | ) | $ | (0.28 | ) | $ | (0.43 | ) | |||||||||||
Diluted | $ | 0.01 | $ | (0.14 | ) | $ | (0.28 | ) | $ | (0.43 | ) | |||||||||||
Non-GAAP basic shares outstanding | 24,599,744 | 21,822,015 | 24,598,816 | 21,822,015 | ||||||||||||||||||
Non-GAAP diluted shares outstanding, if dilutive | 42,049,531 | 21,822,015 | 24,598,816 | 21,822,015 | ||||||||||||||||||
(a) | Effective tax rate for 2018 and 2017 is estimated to be approximately 20% and 37%, respectively. |
Lonestar Resources US Inc.
Unaudited Operating Results
In thousands, except per share and unit data | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
(Restated) | (Restated) | |||||||||||||||
Operating revenues | ||||||||||||||||
Oil | $ | 47,846 | $ | 23,162 | $ | 120,705 | $ | 52,742 | ||||||||
NGLs | 6,795 | 1,890 | 12,939 | 4,820 | ||||||||||||
Natural gas | 4,096 | 1,831 | 9,637 | 5,072 | ||||||||||||
Total operating revenues | $ | 58,737 | $ | 26,883 | $ | 143,281 | $ | 62,634 | ||||||||
Total production volumes by product | ||||||||||||||||
Oil (Bbls) | 660,836 | 483,000 | 1,758,393 | 1,099,098 | ||||||||||||
NGLs (Bbls) | 262,660 | 112,976 | 571,389 | 288,015 | ||||||||||||
Natural gas (Mcf) | 1,343,016 | 653,660 | 3,190,824 | 1,824,186 | ||||||||||||
Total barrels of oil equivalent (BOE) | 1,147,332 | 704,904 | 2,861,586 | 1,690,962 | ||||||||||||
Daily production volumes by product | ||||||||||||||||
Oil (Bbls/d) | 7,183 | 5,250 | 6,441 | 4,026 | ||||||||||||
NGLs (Bbls/d) | 2,855 | 1,228 | 2,093 | 1,055 | ||||||||||||
Natural gas (Mcf/d) | 14,600 | 7,105 | 11,689 | 6,682 | ||||||||||||
Total barrels of oil equivalent (BOE/d) | 12,471 | 7,662 | 10,482 | 6,194 | ||||||||||||
Average realized prices | ||||||||||||||||
Oil ($ per Bbl) | $ | 72.40 | $ | 47.96 | $ | 68.65 | $ | 47.99 | ||||||||
NGLs ($ per Bbl) | 25.87 | 16.19 | 22.64 | 16.74 | ||||||||||||
Natural gas ($ per Mcf) | 3.05 | 2.90 | 3.02 | 2.78 | ||||||||||||
Total oil equivalent, excluding the effect from hedging ($ per BOE) | 51.19 | 38.14 | 50.07 | 37.04 | ||||||||||||
Total oil equivalent, including the effect from hedging ($ per BOE) | 43.97 | 40.66 | 43.62 | 39.31 | ||||||||||||
Operating and other expenses | ||||||||||||||||
Lease operating and gas gathering | $ | 6,687 | $ | 4,576 | $ | 17,761 | $ | 11,053 | ||||||||
Production and ad valorem taxes | 3,218 | 1,541 | 8,145 | 3,656 | ||||||||||||
Depreciation, depletion and amortization | 23,775 | 16,530 | 59,937 | 42,003 | ||||||||||||
General and administrative | 4,661 | 2,644 | 13,385 | 8,925 | ||||||||||||
Interest expense | 10,215 | 5,965 | 28,771 | 19,816 | ||||||||||||
Operating and other expenses per BOE | ||||||||||||||||
Lease operating and gas gathering | $ | 5.83 | $ | 6.49 | $ | 6.21 | $ | 6.54 | ||||||||
Production and ad valorem taxes | 2.80 | 2.19 | 2.85 | 2.16 | ||||||||||||
Depreciation, depletion and amortization | 20.72 | 23.45 | 20.95 | 24.84 | ||||||||||||
General and administrative | 4.06 | 3.75 | 4.68 | 5.28 | ||||||||||||
Interest expense | 8.90 | 8.46 | 10.05 | 11.72 | ||||||||||||
(1) | General and administrative expenses include stock-based compensation |
(2) | Interest expense includes amortization of debt issuance cost, premiums, and discounts |
