Lilis Energy, Inc. (NYSE American: LLEX), an exploration and
production company operating in the Permian Basin of West Texas and
southeastern New Mexico, today reported financial and operating
results for the third quarter of 2019 and announced the formation
of a Special Committee and the engagement of a financial advisor to
explore strategic alternatives.
Third Quarter 2019
Highlights
- Significantly decreased cycle times under the Company’s new
operations team by reducing average drilling days for longer
lateral wells from approximately 45 days (spud to total depth) to
approximately 17 days
- Achieved reduced drilling cycle times by incorporating
oil-based drilling mud, a higher quality rig and better down hole
tools/configurations
- Achieved combined cost savings of over $4.3 million on the
Grizzly A #2H, the Grizzly B #2H and the East Shammo #3H wells due
to reduced drilling days and drilling costs
- Drilled the fastest well by the Company to date, the East
Shammo #3H, at 15 days spud to total depth of 20,715’
- Improved in-zone precision during drilling from approximately
89% in 2018 to approximately 100% in recent wells
- Successfully completed both the Kudu A #2H and the Kudu B #2H
under completion AFE cost estimates, and both wells are currently
on flowback
- Deployed our new operations team with extensive Northern
Delaware Basin experience, which has taken measures to standardize
completion methods and implement the latest techniques
- Received 2-year extended flaring permits to mitigate the need
for future shut-ins associated with regulatory flaring compliance
and successfully brought all four previously shut-in wells back
online and flowing to sales
- Implemented solutions for delivering all produced natural gas
to sales by year-end
- Currently have 24 drilling permits in various stages of
submittal and review with the Bureau of Land Management in New
Mexico and expect to have multiple permits approved by
year-end
- Completed two significant transactions that brought
approximately $56 million of capital into the Company 1.Sold 513
net undeveloped acres in New Mexico, noncontiguous to the Company’s
core operational area, for approximately $33,000 per net
acre2.Completed an overriding royalty interest and working interest
transaction
- Achieved significant G&A cost savings by completing the
closing of the Houston and San Antonio offices, consolidating all
operations to a single location in Fort Worth, and reducing
full-time equivalent employees (corporate, operations and field
personnel) by approximately 28%
- Realized oil pricing of 96% of WTI for the quarter, versus 93%
of WTI in the second quarter of 2019
- Achieved commodity volume mix of 66% liquids, including 53%
crude oil, resulting in 94% of revenue attributable to liquids
sales during the third quarter
Third Quarter 2019 Summary
Production for the third quarter 2019 was
355,504 Boe, or an average of 3,864 Boepd, a decrease of 31% from
third quarter 2018. Average daily oil production for third quarter
2019 totaled 2,053 Bopd, a decrease of 38% from third quarter 2018.
Natural gas liquids (NGL) and natural gas production for third
quarter 2019 totaled 47,225 barrels (Bbls) and 716 million cubic
feet (MMcf), representing a respective 31% decrease and 16%
decrease from third quarter 2018.
The decreases in production resulted primarily
from voluntarily shutting-in additional wells (excluding those
shut-in during the third quarter for regulatory flaring compliance)
related to upgrading surface facilities for natural gas and crude
oil treating. These upgrades are intended to allow deliveries of
all production into our third-party midstream providers’ gathering
systems.
Average realized price for oil, NGLs, and
natural gas for third quarter 2019, excluding the effect of
commodity derivatives, was $54.03 per Bbl, $14.76 per Bbl, and
$0.97 per Mcf, respectively, compared to $52.82 per Bbl, $28.59 per
Bbl, and $1.79 per Mcf, respectively, for third quarter 2018.
Net loss attributable to common stockholders was
$27.6 million, or $0.30 per basic and diluted share, for the three
months ended September 30, 2019, compared to a net loss of $5.3
million, or $0.08 per basic share and $0.09 per diluted share, for
the three months ended September 30, 2018. Total revenue was $11.6
million for the three months ended September 30, 2019, a decrease
of 40% over the comparable quarter in 2018.
Our proved reserves at September 30, 2019 were
approximately 41 MMBOE, with 68% of our proved reserves comprised
of liquids (53% oil and 15% NGLs). Proved reserves PV10 value was
reduced by $61 million primarily as a result of lower pricing used
in accordance with SEC requirements. The reduction resulted in a
full cost ceiling impairment of approximately $16.6 million.
Transaction Overview
On July 31, 2019, the Company successfully
completed an overriding royalty and working interest transaction
(the “ORRI and WI Transaction”) and an asset sale of the “New
Mexico P” acreage, a parcel of 513 net undeveloped acres
noncontiguous to the Company’s core operational area. The
ORRI and WI Transaction includes a buyback option that gives the
Company the right to repurchase the properties at a 1.50x multiple
on invested capital within two years and a 1.75x multiple on
invested capital after two years but before three years. The
New Mexico P acreage transaction equated to approximately $33,000
per net acre with no associated production. Net proceeds from
both the ORRI and WI Transaction and the New Mexico P asset sale
provided approximately $56 million of capital to the Company.
Capital Expenditure
Overview
During the three months ended September 30,
2019, total operational capital expenditures incurred were $14.3
million, with $11.8 related to the 2019 drilling and completion
program. During the third quarter of 2019, the Company
significantly reduced drilling days and drilling costs associated
with the Grizzly A #2H and the Grizzly B #2H wells under the
direction of the Company’s new operations team, achieving the
following results:
- Grizzly A #2H – 1.9 mile lateral, 19.5 drilling days (spud to
TD), $1.5 million savings compared to historical AFEs
- Grizzly B #2H – 1.6 mile lateral, 17.5 drilling days (spud to
TD), $1.4 million savings compared to historical AFEs
- East Shammo #3H – 1.5 mile lateral, 15.2 drilling days (spud to
TD), $1.4 million savings compared to historical AFEs
The reduced drilling cycle times are being
achieved by incorporating oil-based drilling mud, a higher quality
rig and better down hole tools/configurations. This has
reduced the number of bit trips by 44% and increased rate of
penetration 110% over prior wells drilled in early 2019.
Identification of optimal drilling zones within drilling targets
has also reduced time spent slide drilling by 5%. The Company has
also improved in-zone precision from approximately 89% in 2018 to
approximately 100% in recent wells. In addition to these changes,
continuous drilling optimization is being evaluated and implemented
with different hole sizes and configurations to further reduce
cycle times. The Company expects to incorporate these
improved techniques on all future wells with the goal of achieving
similar cost savings.
The Company also completed the Kudu A #2H and
the Kudu B #2H, with the completions coming in under AFE cost
estimates. The Kudu A #2H was the Company’s first test
of a lower Wolfcamp B bench. The well was a 1.5-mile lateral
completed with a slickwater design of 38 stages utilizing mainly
100 Mesh sand. The Kudu B #2H was an upper Wolfcamp B bench
that was slightly over 1 mile in lateral length and was completed
with a slickwater design of 28 stages utilizing mainly 100 Mesh
sand.
Current Operational
Overview
Management continues to focus on overall cost
reductions and efficiencies across all aspects of the
business. The Company has begun several initiatives to reduce
spending on the primary drivers of lease operating expenses,
including contract labor, saltwater disposal, utility expenses, and
equipment rental. Contract labor expenses were
significantly reduced by decreasing full-time equivalent employees
(company, operations and field personnel) by approximately 28%
during the quarter. The Company has also added 32,500 Bbls/d
of saltwater disposal capacity throughout Texas and New Mexico and
is continuing to expand those capabilities. Additionally, the
Company is in the process of fully electrifying the field to remove
the reliance and costs of power generators and is heavily focused
on expanding high pressure gas lines to install artificial lift
across the property in order to reduce related equipment
rentals.
Additionally, the Company completed the Kudu A
#2H and the Kudu B #2H, with the completions coming in under AFE
cost estimates. Both wells are currently on flowback. During the
third quarter, two additional wells were placed on artificial lift,
bringing the total to 11 wells being placed on artificial lift to
date.
Recent Well Results:
- Kudu A #2H – Lower Wolfcamp
B (1.5 mile lateral):
- Currently flowing at a rate of
1,136 Boepd, 813 Bopd (86% liquids, 72% oil), or 150 Boepd per
1,000 lateral ft.
- Kudu B #2H – Upper Wolfcamp
B (1.2 mile lateral):
- Currently flowing at a rate of 649
Boepd, 532 Bopd (91% liquids, 82% oil), or 112 Boepd per 1,000
lateral ft.
- Grizzly A #2H – Upper
Wolfcamp B (1.9 mile lateral):
The Company received 2-year extended flaring
permits to mitigate the need for future shut-ins associated with
regulatory flaring compliance, successfully brought all four
self-elected and previously shut-in wells back online and flowing
to sales and continues to advance efforts with the implementation
of field treating solutions. The treating systems involve
chemical intervention, upgrades to the surface facilities at each
tank battery and upgrades to natural gas handling facilities for
specific wells that do not meet quality specifications. The crude
oil treating implementation is expected to be complete by the end
of November, and the natural gas treating solution continues to be
advanced with the goal of being in a position to deliver all
natural gas production to sales by year-end.
An overview of Lilis’ current drilling
operations and recent well activity can be found in the earnings
presentation posted on the Company website.
Fourth Quarter 2019
Guidance
Early in the fourth quarter, the Company drilled
the East Shammo #3H and completed the Grizzly A #2H. Upon
their completion, the Company shifted focus to production and
facilities optimization while the operations team evaluates the
performance of the recent drilling and completion activity. The
Company currently plans to resume drilling operations in the first
quarter of 2020.
The Company’s fourth quarter guidance includes
production from the Kudu A #2H and the Kudu B #2H, with production
from the Grizzly A #2H layered in as the well comes online during
the quarter. The Company is maintaining its full-year guidance.
Fourth Quarter and Year-end 2019
Guidance
|
3Q'19A |
4Q'19E |
2019E |
Oil Production (MBbls/d) |
|
2.1 |
2.9 –
3.2 |
3.0 –
3.2 |
NGL Production (MBbls/d) |
|
0.5 |
0.5 -
0.7 |
0.7 –
0.8 |
Liquids Production (MBbls/d) |
|
2.6 |
3.4 - 3.9 |
3.7 – 4.0 |
Total Capital Expenditure ($MM) |
$ |
14.3 |
$6 - $8 |
$60 – $70 |
Special Committee and Strategic
Advisor
In conjunction with the Company reporting third
quarter 2019 operating and financial results, the Company also
announced that the Board of Directors has formed a Special
Committee comprised of independent directors tasked with reviewing
and evaluating strategic alternatives that may enhance the value of
the Company, including alternatives that may be available to
identify and access further sources of liquidity. While the Board
has established a Special Committee to review and evaluate
strategic alternatives, no assurances can be given as to the
outcome or timing of the process, or whether any particular
transaction may be pursued or consummated.
The Special Committee has retained Barclays
Capital Inc. as financial advisor to assist in reviewing and
evaluating strategic alternatives.
The Company does not intend to make any future
announcements concerning this process unless and until the Company
otherwise determines that disclosures are necessary or appropriate.
Management continues to engage BMO Capital Markets as financial
advisor to the Company.
Conference Call
Management will host a conference call on
Friday, November 8, 2019 at 11:00 AM Eastern Time to review
financial results and provide an update on corporate
developments.
Participants are asked to preregister for the
call through the following link: http://dpregister.com/10136575
Please note that registered participants will
receive their dial in number upon registration and will dial
directly into the call without delay. Those without internet access
or who are unable to pre-register may dial in by calling:
1-844-695-5520 (domestic), 1-412-902-6761 (international). All
callers should dial in approximately 10 minutes prior to the
scheduled start time and ask to be joined into the Lilis Energy
Inc. call. The conference call will also be available through a
live webcast, which can be accessed via the following link:
https://services.choruscall.com/links/llex191107.html, which
is also available through the company’s website at:
http://investors.lilisenergy.com/events-presentations. A webcast
replay of the call will be available approximately one hour after
the end of the call through February 8, 2020. The replay can be
accessed through the above links.
About Lilis Energy, Inc.
Lilis Energy, Inc. is a Fort Worth based
independent oil and gas exploration and production company that
operates in the Permian’s Delaware Basin, considered among the
leading resource plays in North America. Lilis’ current total
net acreage in the Permian Basin is approximately 20,000 acres.
Lilis Energy's near-term E&P focus is to grow current reserves
and production and pursue strategic acquisitions in its core areas.
For more information, please visit www.lilisenergy.com.
Forward-Looking
Statements:
This press release contains forward-looking
statements within the meaning of the federal securities laws. Such
statements are subject to a number of assumptions, risks and
uncertainties, many of which are beyond the control of the Company.
These risks include, but are not limited to, our ability to
replicate the results described in this release for future wells;
the ability to finance our continued exploration, drilling
operations and working capital needs; all the other uncertainties,
costs and risks involved in exploration and development activities;
and the other risks identified in the Company’s Annual Report on
Form 10-K and its other filings with the Securities and Exchange
Commission. Investors are cautioned that any such statements
are not guarantees of future performance and that actual results or
developments may differ materially from those projected in the
forward-looking statements. The forward-looking statements in
this press release are made as of the date hereof, and the Company
does not undertake any obligation to update the forward-looking
statements as a result of new information, future events or
otherwise.
Forward-looking statements regarding expected
production levels are based upon our estimates of the successful
completion of drilled wells on schedule. Actual sales
production rates from our wells can vary considerably from tested
initial production (IP) rates and are subject to natural decline
rates over the life of the well.
Contact:
Wobbe PloegsmaV.P. Capital Markets &
Investor Relations210-999-5400, ext. 31
Condensed Consolidated Statement of
Operations Information:
|
|
For Three Months EndedSeptember
30, |
|
|
2019 |
|
|
2018 |
|
($ in thousands,
except share and per share data) |
|
|
|
Oil and gas revenue |
|
$ |
11,597 |
|
|
$ |
19,482 |
|
Operating expenses: |
|
|
|
|
Production costs |
|
4,243 |
|
|
3,184 |
|
Gathering, processing and transportation |
|
942 |
|
|
963 |
|
Production taxes |
|
543 |
|
|
1,034 |
|
General and administrative |
|
4,852 |
|
|
6,838 |
|
Depreciation, depletion, amortization and accretion |
|
5,420 |
|
|
7,172 |
|
Impairment of oil and gas properties |
|
16,580 |
|
|
|
Total operating expenses |
|
32,580 |
|
|
19,191 |
|
Operating loss |
|
(20,983 |
) |
|
291 |
|
Other income (expense): |
|
|
|
|
Other income (expense) |
|
(1,183 |
) |
|
− |
Gain (Loss) from commodity derivative |
|
3,943 |
|
|
(4,811 |
) |
Change in fair value of derivative instruments |
|
− |
|
10,612 |
|
Interest expense |
|
(2,186 |
) |
|
(8,948 |
) |
Total other income
(expense) |
|
574 |
|
|
(3,147 |
) |
Net loss before income
tax |
|
(20,409 |
) |
|
(2,856 |
) |
Paid-in-kind dividends on
preferred stock |
|
(7,185 |
) |
|
(2,410 |
) |
Net loss |
|
$ |
(27,594 |
) |
|
$ |
(5,266 |
) |
|
|
|
|
|
Net loss per common
share: |
|
|
|
|
Basic |
|
$ |
(0.30 |
) |
|
$ |
(0.08 |
) |
Diluted |
|
$ |
(0.30 |
) |
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
Weighted average
common shares outstanding: |
|
|
|
|
Basic |
|
91,349,994 |
|
|
64,572,104 |
|
Diluted |
|
91,349,994 |
|
|
88,710,081 |
|
Condensed Consolidated Balance Sheet
Information:
|
|
September 30, 2019 |
|
December 31, 2018 |
|
|
|
($ in thousands, except share and per share
data) |
|
Cash and cash equivalents |
|
$ |
4,339 |
|
|
$ |
21,137 |
|
Accounts receivables, net of
allowance of $11 and $25, respectively |
|
|
23,565 |
|
|
|
20,546 |
|
Derivative assets |
|
|
2,388 |
|
|
|
2,551 |
|
Prepaid expenses and other
current assets |
|
|
2,707 |
|
|
|
1,851 |
|
Total current
assets |
|
|
32,999 |
|
|
|
46,085 |
|
Total oil and natural gas
properties, net |
|
|
426,420 |
|
|
|
430,379 |
|
Total
assets |
|
$ |
474,681 |
|
|
$ |
480,773 |
|
Total current liabilities |
|
$ |
50,304 |
|
|
$ |
76,967 |
|
Total long-term
liabilities |
|
|
190,335 |
|
|
|
217,449 |
|
Total
liabilities |
|
|
240,639 |
|
|
|
294,416 |
|
10,000,000 shares of preferred
stock authorized |
|
|
|
|
|
Series C-1 9.75% Participating
Preferred Stock, 100,000 shares issued and outstanding with a
stated value of $1,175 and $1,093, per share, as of September 30,
2019 and December 31, 2018, respectively |
|
|
77,582 |
|
|
|
106,774 |
|
Series C-2 9.75% Participating
Preferred Stock, 25,000 shares issued and outstanding with a stated
value of $1,101 and $1,024, per share, as of September 30, 2019 and
December 31, 2018, respectively |
|
|
18,186 |
|
|
|
25,522 |
|
Series D 8.25% Participating
Preferred Stock, 39,254 shares issued and outstanding with a stated
value of $1,085 and $1,021, per share, as of September 30, 2019 and
December 31, 2018, respectively |
|
|
28,202 |
|
|
|
40,729 |
|
Series E 8.25% Convertible
Participating Preferred Stock, 60,000 shares issued and outstanding
with a stated value of $1,048, per share, as of September 30,
2019 |
|
|
64,988 |
|
|
|
— |
|
Series F 9.00% Participating
Preferred Stock, 55,000 shares issued and outstanding with a stated
value of $1,052, per share, as of September 30, 2019 |
|
|
49,559 |
|
|
|
— |
|
Total stockholders’ equity
(91,796,964 and 71,182,016 common shares issued and outstanding as
of September 30, 2019 and December 31, 2018, respectively) |
|
|
(4,475 |
) |
|
|
13,332 |
|
Total liabilities and
stockholders’ equity |
|
$ |
474,681 |
|
|
$ |
480,773 |
|
|
|
|
|
|
|
|
|
Condensed Consolidated Statement of Cash Flows
Information:
|
|
Nine months Ended September
30, |
|
|
|
2019 |
|
|
2018 |
|
|
|
($ in thousands) |
|
Net cash provided by
(used in): |
|
|
|
|
|
Operating activities |
|
$ |
(42,385 |
) |
|
$ |
83,679 |
|
Investing activities |
|
(38,717 |
) |
|
(190,906 |
) |
Financing activities |
|
64,304 |
|
|
114,719 |
|
|
|
|
|
|
|
Non-GAAP Adjusted EBITDAX
|
|
For the
Three Months Ended |
|
|
September 30, |
|
|
2019 |
|
|
2018 |
|
Reconciliation of
Adjusted EBITDAX: |
|
|
Net income (loss) |
$ |
(20,409 |
) |
$ |
(2,856 |
) |
Non-cash equity-based
compensation |
|
332 |
|
|
2,100 |
|
Interest expense, net |
|
2,186 |
|
|
8,949 |
|
Depreciation, depletion,
amortization and accretion |
|
5,420 |
|
|
7,172 |
|
Loss (gain) from fair value
changes of debt conversion and warrant derivatives |
|
1,299 |
|
|
(10,612 |
) |
Unrealized loss (gain) from
commodity derivatives, net |
|
(4,383 |
) |
|
6,521 |
|
Other expense (income),
net |
|
- |
|
|
(1 |
) |
842 Gain/Loss |
|
(115 |
) |
|
- |
|
Impairment |
|
16,580 |
|
|
- |
|
Non-recurring expenses |
|
2,818 |
|
|
1,148 |
|
Adjusted EBITDAX |
$ |
3,727 |
|
$ |
12,421 |
|
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