Approach Resources Inc. (NASDAQ:AREX) today reported financial and
operational results for the fourth quarter and full-year 2016 and
estimated 2016 proved reserves.
Fourth Quarter 2016 Highlights
- Production was 12.0 MBoe/d, exceeding quarterly guidance
- Record low quarterly lease operating expense (“LOE”) of $3.40
per Boe
- Cash operating expenses decreased 14% from the prior-year
quarter
- Revenues were $26.5 million, an increase of 12% from the prior
quarter
Full-Year 2016 and Other Highlights
- Production was 12.4 MBoe/d, exceeding midpoint of annual
guidance
- Record low annual LOE of $4.24 per Boe
- Record low drilling and completion costs of $3.5 million per
well, a reduction of 22% over prior year
- Drilled six and completed five wells using positive cash flow
generated from our operations, with no increase in debt
- We are encouraged with the results of our new generation
completions and once we have additional production data we plan to
update our type curves to reflect the EUR improvements
- Reserve replacement ratio of 350%
- Reached an agreement to reduce senior note debt by $130.6
million and future interest expense by $40 million through
debt-for-equity exchange, subsequently closed in January 2017
Management Comment
Ross Craft, Approach’s Chairman and CEO commented, “In 2016, we
delivered exceptional operational results while maintaining our
focus on reducing costs and increasing operating
efficiencies. We achieved record low LOE and drilling and
completion costs during the year, and successfully managed our
natural production decline. We also negotiated, and
subsequently closed in January 2017, a transformational, strategic
deleveraging transaction that reduced outstanding debt by $130.6
million and future interest expense by $40 million, and launched an
exchange offer for our remaining $99.8 million of senior notes. We
are excited to have three new board members and to align ourselves
with a strategic investor that has the depth of knowledge in the
oilfield services and energy business of the Wilks Family Office,
our new largest shareholder. Capitalizing on the increase in
commodity prices, we hedged approximately 85% of 2017 forecasted
natural gas and 50% of NGL production. While continuing to operate
within our cash flow in 2017, we expect to resume production growth
from our year-end 2016 exit rate. We believe we are well-positioned
to create value for our shareholders by strengthening our balance
sheet, building on our asset base and continuing to be the
lowest-cost operator in the Midland Basin.”
Fourth Quarter 2016 Results
Production for fourth quarter 2016 totaled 1,106 MBoe (12.0
MBoe/d), made up of 28% oil, 34% NGLs and 38% natural gas.
Average realized commodity prices for fourth quarter 2016, before
the effect of commodity derivatives, were $46.02 per Bbl of oil,
$15.25 per Bbl of NGLs and $2.65 per Mcf of natural gas. Our
average realized price, including the effect of commodity
derivatives, was $24.36 per Boe for fourth quarter 2016.
Net loss for fourth quarter 2016 was $13.5 million, or $0.32 per
diluted share, on revenues of $26.5 million. Net loss for
fourth quarter 2016 also included an unrealized loss on commodity
derivatives of $3.3 million and a realized gain on commodity
derivatives of $0.4 million. Excluding the unrealized loss on
commodity derivatives, adjusted net loss (non-GAAP) for fourth
quarter 2016 was $11.3 million, or $0.27 per diluted share, which
includes a non-cash charge of $0.04 per share related to a deferred
tax asset reversal arising from our share-based compensation.
EBITDAX (non-GAAP) for fourth quarter 2016 was $15.5 million.
See “Supplemental Non-GAAP Financial and Other Measures” below for
our reconciliation of adjusted net loss and EBITDAX to net
loss.
LOE averaged $3.40 per Boe. Production and ad valorem
taxes averaged $2.43 per Boe, or 10.1% of oil, NGLs and gas
sales. Exploration costs were $0.62 per Boe. Total
general and administrative (“G&A”) costs averaged $6.35 per
Boe, including cash G&A costs of $4.55 per Boe.
Depletion, depreciation and amortization expense averaged $17.54
per Boe. Interest expense totaled $7.1 million.
Full-Year 2016 Results
Production for 2016 was 4,537 MBoe (12.4 MBoe/d), made up of 28%
oil, 34% NGLs and 38% natural gas. Average realized commodity
prices for 2016, before the effect of commodity derivatives, were
$37.90 per Bbl of oil, $12.93 per Bbl of NGLs and $2.14 per Mcf of
natural gas. Our average realized price, including the effect
of commodity derivatives, was $21.25 per Boe for 2016.
Net loss for 2016 was $52.2 million, or $1.26 per diluted share,
on revenues of $90.3 million. Net loss for 2016 included an
unrealized loss on commodity derivatives of $11.6 million and a
realized gain on commodity derivatives of $6.1 million.
Excluding the unrealized loss on commodity derivatives and
write-off of debt issuance costs of $0.6 million, adjusted net loss
(non-GAAP) for 2016 was $44.3 million, or $1.07 per diluted share,
which includes a non-cash charge of $0.05 per share related to a
deferred tax asset reversal arising from our share-based
compensation. EBITDAX (non-GAAP) for 2016 was $52
million. See “Supplemental Non-GAAP Financial and Other
Measures” below for our reconciliation of adjusted net loss and
EBITDAX to net loss.
LOE averaged $4.24 per Boe, a 19% decrease from the prior
year. Production and ad valorem taxes averaged $1.81 per Boe,
or 9.1% of oil, NGLs and gas sales. Exploration costs were
$0.86 per Boe. Total G&A costs averaged $5.45 per Boe,
including cash G&A costs of $4.07 per Boe. Depletion,
depreciation and amortization expense averaged $17.42 per
Boe. Interest expense totaled $27.3 million.
Adjusted net loss, EBITDAX, cash operating expenses and PV-10
are non-GAAP measures. See “Supplemental Non-GAAP Financial and
Other Measures” below for our definitions and reconciliations of
adjusted net loss and EBITDAX to net loss, cash operating expenses
to operating expenses and PV-10 to the standardized measure (GAAP)
and our definition and calculation of liquidity.
Operations Update
In 2016, we focused on operating within cash flow while managing
natural production decline, improving cost structure and increasing
efficiencies. During 2016, we drilled a total of six
horizontal wells and completed five. Of these, two wells were
drilled to the A bench, one well was drilled to the B bench and
three wells were drilled to the C bench. The five completed
wells are tracking at a type curve of approximately 678 Mboe,
including one well normalized for a 7,500 foot lateral
length. At December 31, 2016, we had six horizontal wells
waiting on completion.
With our new generation frac design, we are very encouraged by
the well results and expect to update our type curves to reflect
the EUR improvements once we have additional production data. We
currently are running one horizontal rig in Project Pangea and have
completed two University wells that are in the early stage of
flowback.
We managed our natural production decline through surface
facility optimization, operating efficiencies and investment in
well repairs, workovers and maintenance. During the first
quarter of 2016, our production decreased by 12% compared to the
prior quarter due to no new well completions from August 2015
through first quarter 2016, and the reservoir’s natural production
decline. After the first quarter 2016, further production decline
was limited to 1%, 3% and 1% in the second, third and fourth
quarters of 2016, respectively.
Our extensive infrastructure network of centralized production
facilities, water transportation, handling and recycling system,
gas lift lines and salt water disposal wells continue to provide
competitive advantages in driving down drilling and completion, and
operating costs. In 2016, we were able to reduce our drilling
and completion costs by 22% to $3.5 million per well and LOE per
Boe by 19% to $4.24 per Boe.
Strategic Deleveraging Transaction
On November 2, 2016, we entered into an exchange agreement with
Wilks Brothers, LLC and SDW Investments, LLC, entities beneficially
owned by the Wilks Family Office and collectively the largest
holder of the Company’s 7.00% senior notes due 2021, to exchange
$130.6 million principal amount of senior notes, for 39,165,600 new
shares of our common stock. This exchange was completed on January
27, 2017, resulting in a reduction in principal amount of our
senior notes of $130.6 million and approximately $40
million in future interest savings. The exchange ratio implied
a valuation of $3.33 per share and represented a 23% premium to the
closing price of our common stock on November 2, 2016, the
date of the exchange agreement.
Immediately following the close of the exchange, we launched an
offer to exchange our common stock for the remaining $99.8 million
of our outstanding senior notes at an exchange ratio of 276 shares
of common stock per $1,000 principal amount of senior notes, which
we anticipate closing in the first quarter of 2017.
Fourth Quarter and Full-Year 2016
Production
Estimated fourth quarter 2016 production totaled 1,106 MBoe
(12.0 MBoe/d). Estimated full-year 2016 production totaled
4,537 MBoe (12.4 MBoe/d).
|
Three and 12 Months
EndedDecember 31, 2016 |
|
Three months |
|
|
12 months |
|
Production: |
|
|
|
|
|
Oil
(MBbls) |
304 |
|
|
1,275 |
|
NGLs
(MBbls) |
380 |
|
|
1,529 |
|
Gas
(MMcf) |
2,530 |
|
|
10,404 |
|
Total
(MBoe) |
1,106 |
|
|
4,537 |
|
Total
(MBoe/d) |
12.0 |
|
|
12.4 |
|
|
|
|
|
|
|
2016 Estimated Proved Reserves and Costs
Incurred
Year-end 2016 proved reserves totaled 156.4 MMBoe.
Year-end 2016 proved reserves were 32% oil, 30% NGLs and 38%
natural gas. Proved developed reserves represent
approximately 38% of total year-end 2016 proved reserves.
At December 31, 2016, substantially all of our proved reserves
were located in our core operating area in the southern Midland
Basin. Year-end 2016 estimated proved reserves included 145.4
MMBoe attributable to the horizontal Wolfcamp shale play.
The table below illustrates our horizontal Wolfcamp and other
reserves over the last three years ended December 31, 2016, 2015,
and 2014.
|
Proved Reserves (Mboe) |
|
2016 |
|
2015 |
|
2014 |
Horizontal
Wolfcamp |
|
|
|
|
|
Proved
developed |
47,861 |
|
|
49,843 |
|
|
40,678 |
|
Proved
undeveloped |
97,502 |
|
|
104,790 |
|
|
84,138 |
|
Total |
145,363 |
|
|
154,633 |
|
|
124,816 |
|
Percent
of total proved reserves |
93 |
% |
|
93 |
% |
|
85 |
% |
|
|
|
|
|
|
Other
Vertical |
|
|
|
|
|
Proved
developed |
11,014 |
|
|
12,013 |
|
|
19,542 |
|
Proved
undeveloped |
- |
|
|
- |
|
|
1,890 |
|
Total |
11,014 |
|
|
12,013 |
|
|
21,432 |
|
Percent
of total proved reserves |
7 |
% |
|
7 |
% |
|
15 |
% |
|
|
|
|
|
|
Total proved
reserves |
156,377 |
|
|
166,646 |
|
|
146,248 |
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries for 2016 were 16.7 MMBoe, primarily
attributable to our development project in the Wolfcamp shale oil
resource play in the Permian Basin. During 2016, we
reclassified 22.2 MMBoe of proved undeveloped reserves that are not
expected to be developed within five years under Securities and
Exchange Commission (“SEC”) rules to probable reserves.
Revisions also included an increase of 2.1 MMBoe of proved reserves
resulting from cost reductions, updated well performance and
technical parameters, offset by a decrease of 1.9 MMBoe of proved
reserves due to lower commodity prices.
The following table summarizes the changes in our estimated
proved reserves during 2016.
|
Oil (MBbls) |
|
|
NGLs (MBbls) |
|
|
Natural Gas (MMcf) |
|
|
Total (MBoe) |
|
Balance – December 31, 2015 |
54,496 |
|
|
49,486 |
|
|
375,988 |
|
|
166,646 |
|
Extensions and discoveries |
6,529 |
|
|
4,564 |
|
|
33,347 |
|
|
16,651 |
|
Production (1) |
(1,275 |
) |
|
(1,529 |
) |
|
(11,734 |
) |
|
(4,759 |
) |
Revisions |
(9,719 |
) |
|
(4,887 |
) |
|
(45,324 |
) |
|
(22,161 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Balance – December 31, 2016 |
50,031 |
|
|
47,634 |
|
|
352,277 |
|
|
156,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve
replacement ratio |
|
|
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries / Production |
|
|
|
|
350% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Production includes 1,330 MMcf related to field
fuel. |
|
|
|
|
|
|
|
|
|
|
|
|
|
Our preliminary, unaudited estimate of the standardized
after-tax measure of discounted future net cash flows
(“standardized measure”) of our proved reserves at December 31,
2016, was $297.8 million. The PV-10, or pre-tax present value
of our proved reserves discounted at 10%, of our proved reserves at
December 31, 2016, was $307.9 million ($730.2 million at December
31, 2016 NYMEX strip).
The independent engineering firm DeGolyer and MacNaughton
prepared our estimates of year-end 2016 proved reserves and PV-10
at SEC pricing. PV-10 is a non-GAAP measure. See
“Supplemental Non-GAAP Financial and Other Measures” below for our
definition of PV-10 and reconciliation to the standardized measure
(GAAP). Our reserve estimates and our calculation of
standardized measure and PV-10 are based on the 12-month average of
the first-day-of-the-month pricing of $42.69 per Bbl of oil, $14.12
per Bbl of NGLs and $2.47 per MMBtu of natural gas during 2016.
At NYMEX strip pricing at December 31, 2016, PV-10 is
$730.2 million. The following table summarizes the NYMEX strip
prices at December 31, 2016.
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
2020 |
|
|
2021(1) |
Oil (per Bbl) |
$ |
56.19 |
|
|
$ |
56.59 |
|
|
$ |
56.10 |
|
|
$ |
56.05 |
|
|
$ |
56.21 |
Natural Gas (per MMBtu) |
$ |
3.61 |
|
|
$ |
3.14 |
|
|
$ |
2.87 |
|
|
$ |
2.88 |
|
|
$ |
2.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Subsequent year prices were held flat for the
remaining lives of the properties. |
(2) NGLs prices per Bbl were estimated at 40% of
the oil strip price. |
|
Net capital expenditures incurred during 2016 totaled $19.8
million and were attributable to drilling and development ($17.8
million) and infrastructure projects and equipment ($3.1 million),
and included a positive legal settlement with a service provider
($1.1 million).
Guidance
The Company’s capital budget for 2017 is a range of $50 million
to $70 million depending on commodity prices. We currently are
operating one rig. The table below sets forth our production and
operating costs and expenses guidance for 2017.
|
|
2017 Guidance |
Capital expenditures (in millions) |
|
$50 – $70 |
Production: |
|
|
Oil (MBbls) |
|
1,200 – 1,300 |
NGLs (MBbls) |
|
1,380 – 1,460 |
Gas (MMcf) |
|
9,500
– 10,160 |
Total (MBoe) |
|
4,163 – 4,453 |
|
|
|
Cash operating costs (per Boe): |
|
|
Lease operating |
$ |
4.00 –
5.00 |
Production and ad valorem taxes |
|
8.5%
of oil & gas revenues |
Cash general and administrative |
$ |
4.00 –
5.00 |
Non-cash operating costs (per Boe): |
|
|
Non-cash general and administrative |
$ |
1.00 –
1.50 |
Exploration |
$ |
0.50 –
1.00 |
Depletion, depreciation and amortization |
$ |
17.00
– 19.00 |
|
|
|
First quarter 2017 production is estimated to be approximately
11.3 MBoe/d. First quarter 2017 production will be affected
by no new well completions in the fourth quarter of 2016, weather
and RVP pipeline specification issues in first quarter 2017.
We expect to resume quarterly production growth starting in the
second quarter of 2017.
As further discussed below under “Forward-Looking and Cautionary
Statements,” our guidance is forward-looking information that is
subject to a number of risks and uncertainties, many of which are
beyond our control. In addition, our 2017 capital budget
excludes acquisitions and lease extensions and renewals and is
subject to change depending upon a number of factors, including
prevailing and anticipated prices for oil, NGLs and natural gas,
results of horizontal drilling and completions, economic and
industry conditions at the time of drilling, the availability of
sufficient capital resources for drilling prospects, our financial
results and the availability of lease extensions and renewals on
reasonable terms.
Liquidity Update
At December 31, 2016, we had a $1 billion senior secured
revolving credit facility in place with a borrowing base of $325
million. At December 31, 2016, our liquidity and long-term
debt-to-capital ratio were approximately $51.4 million and 47%,
respectively. See “Supplemental Non-GAAP Financial and Other
Measures” below for our definitions and calculation of liquidity
and long-term debt-to-capital.
Commodity Derivatives Update
We enter into commodity derivatives positions to reduce the risk
of commodity price fluctuations. At present, approximately
85% of 2017 forecasted natural gas and 50% of NGL production is
hedged. The table below is a summary of our current
derivatives positions.
Commodity and Period |
|
Contract Type |
|
Volume Transacted |
|
Contract Price |
Natural
Gas |
|
|
|
|
|
|
January 2017 — March
2017 |
|
Swap |
|
100,000 MMBtu/month |
|
$2.463/MMBtu |
January 2017 — March
2017 |
|
Swap |
|
300,000 MMBtu/month |
|
$2.45/MMBtu |
January 2017 — March
2017 |
|
Swap |
|
200,000 MMBtu/month |
|
$3.287/MMBtu |
January 2017 — December
2017 |
|
Collar |
|
100,000 MMBtu/month |
|
$3.00/MMBtu - $3.65/MMBtu |
April 2017 — December
2017 |
|
Collar |
|
200,000 MMBtu/month |
|
$2.30/MMBtu - $2.60/MMBtu |
April 2017 — December
2017 |
|
Collar |
|
200,000 MMBtu/month |
|
$3.00/MMBtu - $3.44/MMBtu |
April 2017 — December
2017 |
|
Collar |
|
200,000 MMBtu/month |
|
$3.00/MMBtu - $3.50/MMBtu |
January 2018 — December
2018 |
|
Swap |
|
200,000 MMBtu/month |
|
$3.085/MMBtu |
January 2018 — December
2018 |
|
Swap |
|
250,000 MMBtu/month |
|
$3.084/MMBtu |
NGLs (C2 -
Ethane) |
|
|
|
|
|
|
February 2017 —
December 2017 |
|
Swap |
|
1,050 Bbls/day |
|
$11.34/Bbl |
NGLs (C3 -
Propane) |
|
|
|
|
|
|
February 2017 —
December 2017 |
|
Swap |
|
750 Bbls/day |
|
$27.916/Bbl |
NGLs (IC4 -
Isobutane) |
|
|
|
|
|
|
February 2017 —
December 2017 |
|
Swap |
|
75 Bbls/day |
|
$36.7325/Bbl |
NGLs (NC4 -
Butane) |
|
|
|
|
|
|
February 2017 —
December 2017 |
|
Swap |
|
250 Bbls/day |
|
$35.9205/Bbl |
|
|
|
|
|
|
|
Conference Call Information and Summary
Presentation
The Company will host a conference call on Friday, March 10,
2017, at 9:00 a.m. Central Time (10:00 a.m. Eastern Time) to
discuss fourth quarter and full-year 2016 financial and operational
results. Those wishing to listen to the conference call, may
do so by visiting the Events page under the Investor Relations
section of the Company’s website, www.approachresources.com, or by
phone:
Dial
in: |
|
(844) 884-9950 /
Conference ID: 70306606 |
International Dial In: |
|
(661) 378-9660 |
|
|
|
A replay of the call will be available on the Company’s website
or by dialing: |
|
|
|
Dial
in: |
|
(855) 859-2056 /
Passcode: 70306606 |
|
|
|
In addition, a fourth quarter and full-year 2016 summary
presentation will be available on the Company’s website.
About Approach Resources
Approach Resources Inc. is an independent
energy company focused on the exploration, development, production
and acquisition of unconventional oil and natural gas reserves in
the Midland Basin of the greater Permian Basin in West Texas.
For more information about the Company, please visit
www.approachresources.com. Please note that the Company
routinely posts important information about the Company under the
Investor Relations section of its website.
This press release contains forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. All statements,
other than statements of historical facts, included in this press
release that address activities, events or developments that the
Company expects, believes or anticipates will or may occur in the
future are forward-looking statements. Without limiting the
generality of the foregoing, forward-looking statements contained
in this press release specifically include expectations of
anticipated financial and operating results. These statements
are based on certain assumptions made by the Company based on
management’s experience, perception of historical trends and
technical analyses, current conditions, anticipated future
developments and other factors believed to be appropriate and
reasonable by management. When used in this press release, the
words “will,” “potential,” “believe,” “estimate,” “intend,”
“expect,” “may,” “should,” “anticipate,” “could,” “plan,”
“predict,” “project,” “profile,” “model” or their negatives, other
similar expressions or the statements that include those words, are
intended to identify forward-looking statements, although not all
forward-looking statements contain such identifying words. Such
statements are subject to a number of assumptions, risks and
uncertainties, many of which are beyond the control of the Company,
which may cause actual results to differ materially from those
implied or expressed by the forward-looking statements. Further
information on such assumptions, risks and uncertainties is
available in the Company’s SEC filings. The Company’s SEC
filings are available on the Company’s website at
www.approachresources.com. Any forward-looking statement
speaks only as of the date on which such statement is made and the
Company undertakes no obligation to correct or update any
forward-looking statement, whether as a result of new information,
future events or otherwise, except as required by applicable
law.
|
UNAUDITED RESULTS OF OPERATIONS |
|
|
|
|
|
Three Months EndedDecember
31, |
|
Twelve Months EndedDecember
31, |
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
Oil |
$ |
14,007 |
|
|
$ |
15,028 |
|
|
$ |
48,311 |
|
|
$ |
82,170 |
|
NGLs |
|
5,798 |
|
|
|
4,370 |
|
|
|
19,761 |
|
|
|
20,437 |
|
Gas |
|
6,700 |
|
|
|
6,094 |
|
|
|
22,230 |
|
|
|
28,729 |
|
Total
oil, NGLs and gas sales |
26,505 |
|
|
25,492 |
|
|
90,302 |
|
|
131,336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on commodity derivatives |
442 |
|
|
14,552 |
|
|
6,132 |
|
|
52,489 |
|
Total
oil, NGLs and gas sales including derivative impact |
$ |
26,947 |
|
|
$ |
40,044 |
|
|
$ |
96,434 |
|
|
$ |
183,825 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbls) |
304 |
|
|
400 |
|
|
1,275 |
|
|
1,882 |
|
NGLs
(MBbls) |
380 |
|
|
428 |
|
|
1,529 |
|
|
1,694 |
|
Gas
(MMcf) |
2,530 |
|
|
3,011 |
|
|
10,404 |
|
|
11,732 |
|
Total
(MBoe) |
1,106 |
|
|
1,330 |
|
|
4,537 |
|
|
5,532 |
|
Total
(MBoe/d) |
12.0 |
|
|
14.5 |
|
|
12.4 |
|
|
15.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
prices: |
|
|
|
|
|
|
|
|
|
|
|
Oil (per
Bbl) |
$ |
46.02 |
|
|
$ |
37.60 |
|
|
$ |
37.90 |
|
|
$ |
43.65 |
|
NGLs (per
Bbl) |
|
15.25 |
|
|
|
10.20 |
|
|
|
12.93 |
|
|
|
12.06 |
|
Gas (per
Mcf) |
|
2.65 |
|
|
|
2.02 |
|
|
|
2.14 |
|
|
|
2.45 |
|
Total
(per Boe) |
$ |
23.96 |
|
|
$ |
19.17 |
|
|
$ |
19.90 |
|
|
$ |
23.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on
commodity derivatives (per Boe) |
0.40 |
|
|
10.94 |
|
|
1.35 |
|
|
9.49 |
|
Total
including derivative impact (per Boe) |
$ |
24.36 |
|
|
$ |
30.11 |
|
|
$ |
21.25 |
|
|
$ |
33.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and
expenses (per Boe): |
|
|
|
|
|
|
|
|
|
|
|
Lease
operating |
$ |
3.40 |
|
|
$ |
5.44 |
|
|
$ |
4.24 |
|
|
$ |
5.24 |
|
Production and ad valorem taxes |
2.43 |
|
|
1.94 |
|
|
1.81 |
|
|
2.00 |
|
Exploration |
0.62 |
|
|
0.17 |
|
|
0.86 |
|
|
0.80 |
|
General
and administrative(1) |
6.35 |
|
|
4.10 |
|
|
5.45 |
|
|
5.12 |
|
Depletion, depreciation and amortization |
17.54 |
|
|
17.42 |
|
|
17.42 |
|
|
19.76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Below
is a summary of general and administrative expense: |
|
|
|
|
|
|
|
|
|
|
|
General
and administrative – cash Component |
$ |
4.55 |
|
|
$ |
2.63 |
|
|
$ |
4.07 |
|
|
$ |
3.68 |
|
General
and administrative – noncash Component |
1.80 |
|
|
1.47 |
|
|
1.38 |
|
|
1.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
APPROACH RESOURCES INC. AND
SUBSIDIARIES |
UNAUDITED CONSOLIDATED STATEMENTS OF
OPERATIONS |
(In thousands, except shares and per-share
amounts) |
|
|
|
|
|
|
|
|
Three Months Ended |
|
Twelve Months Ended |
|
|
|
December 31, |
|
December 31, |
|
|
|
2016 |
|
2015 |
|
2016 |
|
2015 |
|
REVENUES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, NGLs
and gas sales |
|
$ |
26,505 |
|
$ |
|
25,492 |
|
$ |
|
90,302 |
|
$ |
|
131,336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating |
|
|
3,766 |
|
|
|
7,228 |
|
|
|
19,250 |
|
|
|
28,972 |
|
Production and ad valorem taxes |
|
|
2,685 |
|
|
|
2,583 |
|
|
|
8,217 |
|
|
|
11,085 |
|
Exploration |
|
|
685 |
|
|
|
228 |
|
|
|
3,923 |
|
|
|
4,439 |
|
General
and administrative |
|
|
7,026 |
|
|
|
5,459 |
|
|
|
24,734 |
|
|
|
28,341 |
|
Termination costs |
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
1,436 |
|
Impairment of oil and gas properties |
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
220,197 |
|
Depletion, depreciation and amortization |
|
|
19,402 |
|
|
|
23,173 |
|
|
|
79,044 |
|
|
|
109,319 |
|
Total
expenses |
|
|
33,564 |
|
|
|
38,671 |
|
|
|
135,168 |
|
|
|
403,789 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
LOSS |
|
|
(7,059 |
) |
|
|
(13,179 |
) |
|
|
(44,866 |
) |
|
|
(272,453 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense, net |
|
|
(7,086 |
) |
|
|
(6,436 |
) |
|
|
(27,259 |
) |
|
|
(25,066 |
) |
Gain on
debt extinguishment |
|
|
– |
|
|
|
9,080 |
|
|
|
– |
|
|
|
10,563 |
|
Write-off
of debt issuance costs |
|
|
– |
|
|
|
– |
|
|
|
(563 |
) |
|
|
– |
|
Realized
gain on commodity derivatives |
|
|
442 |
|
|
|
14,552 |
|
|
|
6,132 |
|
|
|
52,489 |
|
Unrealized loss on commodity derivatives |
|
|
(3,343 |
) |
|
|
(10,285 |
) |
|
|
(11,616 |
) |
|
|
(33,214 |
) |
Other
income |
|
|
– |
|
|
|
225 |
|
|
|
1,511 |
|
|
|
172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS BEFORE
INCOME TAX BENEFIT |
|
|
(17,046 |
) |
|
|
(6,043 |
) |
|
|
(76,661 |
) |
|
|
(267,509 |
) |
INCOME TAX
BENEFIT: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
– |
|
|
|
(265 |
) |
|
|
– |
|
|
|
(265 |
) |
Deferred |
|
|
(3,571 |
) |
|
|
(19 |
) |
|
|
(24,418 |
) |
|
|
(93,140 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
LOSS |
|
$ |
(13,475 |
) |
|
$ |
(5,759 |
) |
|
$ |
(52,243 |
) |
|
$ |
(174,104 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER
SHARE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.32 |
) |
|
$ |
(0.14 |
) |
|
$ |
(1.26 |
) |
|
$ |
(4.30 |
) |
Diluted |
|
$ |
(0.32 |
) |
|
$ |
(0.14 |
) |
|
$ |
(1.26 |
) |
|
$ |
(4.30 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE SHARES OUTSTANDING: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
41,705,462 |
|
|
|
40,598,098 |
|
|
|
41,488,206 |
|
|
|
40,464,283 |
|
Diluted |
|
|
41,705,462 |
|
|
|
40,598,098 |
|
|
|
41,488,206 |
|
|
|
40,464,283 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UNAUDITED SELECTED FINANCIAL DATA |
|
|
|
Unaudited Consolidated Balance Sheet
Data |
|
December 31, |
(in thousands) |
|
2016 |
|
2015 |
Cash and
cash equivalents |
|
$ |
21 |
|
$ |
600 |
Other
current assets |
|
|
12,473 |
|
|
19,838 |
Property
and equipment, net, successful efforts method |
|
|
1,092,061 |
|
|
1,154,546 |
Total assets |
|
$ |
1,104,555 |
|
$ |
1,174,984 |
|
|
|
|
|
|
|
Current
liabilities |
|
$ |
26,369 |
|
$ |
28,508 |
Long-term
debt (1) |
|
|
498,349 |
|
|
496,587 |
Other
long-term liabilities |
|
|
16,885 |
|
|
41,922 |
Stockholders’ equity |
|
|
562,952 |
|
|
607,967 |
Total liabilities and stockholders’ equity |
|
$ |
1,104,555 |
|
$ |
1,174,984 |
|
|
|
|
|
|
|
(1) Long-term debt at December 31, 2016, is comprised
of $230.3 million in 7% senior notes due 2021 and $273 million in
outstanding borrowings under our senior secured credit facility,
net of issuance costs of $5 million. Long-term debt at
December 31, 2015, is comprised of $230.3 million in 7% senior
notes due 2021 and $273 million in outstanding borrowings under our
senior secured credit facility, net of issuance costs of $6.7
million. |
|
Unaudited Consolidated Cash Flow Data |
|
Twelve Months Ended December 31, |
|
(in thousands) |
|
2016 |
|
2015 |
|
Net cash provided
(used) by: |
|
|
|
|
|
|
|
Operating
activities |
|
$ |
26,081 |
|
$ |
102,716 |
|
Investing
activities |
|
$ |
(23,890 |
) |
$ |
(217,347 |
) |
Financing
activities |
|
$ |
(2,770 |
) |
$ |
114,799 |
|
|
|
|
|
|
|
|
|
Supplemental Non-GAAP Financial and Other
Measures
This release contains certain financial measures that are
non-GAAP measures. We have provided reconciliations
below of the non-GAAP financial measures to the most directly
comparable GAAP financial measures and on the Non-GAAP Financial
Information page under the Financial Reporting subsection of the
Investor Relations section of our website at
www.approachresources.com.
Adjusted Net Loss
This release contains the non-GAAP financial measures adjusted
net loss and adjusted net loss per diluted share, which exclude (1)
unrealized loss on commodity derivatives, (2) write-off of debt
issuance costs, (3) rig termination fees, (4) impairment of oil and
gas properties, (5) termination costs, (6) gain on debt
extinguishment, and (7) related income tax effect. The amounts
included in the calculation of adjusted net loss and adjusted net
loss per diluted share below were computed in accordance with GAAP.
We believe adjusted net loss and adjusted net loss per diluted
share are useful to investors because they provide readers with a
meaningful measure of our profitability before recording certain
items whose timing or amount cannot be reasonably determined.
However, these measures are provided in addition to, and not as an
alternative for, and should be read in conjunction with, the
information contained in our financial statements prepared in
accordance with GAAP (including the notes), included in our SEC
filings and posted on our website.
The table below provides a reconciliation of adjusted net loss
to net loss for the three and twelve months ended December 31, 2016
and 2015 (in thousands, except per-share amounts).
|
Three Months Ended December
31, |
|
|
Twelve Months Ended December
31, |
|
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
|
Net loss |
$ |
(13,475 |
) |
|
$ |
(5,759 |
) |
|
$ |
(52,243 |
) |
|
$ |
(174,104 |
) |
Adjustments for
certain items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on commodity derivatives |
|
3,343 |
|
|
|
10,285 |
|
|
|
11,616 |
|
|
|
33,214 |
|
Write-off
of debt issuance costs |
|
– |
|
|
|
– |
|
|
|
563 |
|
|
|
– |
|
Rig
termination fees |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
2,199 |
|
Impairment of oil and gas properties |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
220,197 |
|
Termination costs |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
1,436 |
|
Gain on
debt extinguishment |
|
– |
|
|
|
(9,080 |
) |
|
|
– |
|
|
|
(10,563 |
) |
Related
income tax effect |
|
(1,170 |
) |
|
|
(422 |
) |
|
|
(4,263 |
) |
|
|
(87,348 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net loss |
$ |
(11,302 |
) |
|
$ |
(4,976 |
) |
|
$ |
(44,327 |
) |
|
$ |
(14,969 |
) |
Adjusted net loss per diluted share |
$ |
(0.27 |
) |
|
$ |
(0.12 |
) |
|
$ |
(1.07 |
) |
|
$ |
(0.37 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
We define EBITDAX as net loss, plus (1) exploration expense, (2)
depletion, depreciation and amortization expense, (3) share-based
compensation expense, (4) unrealized loss on commodity derivatives,
(5) impairment of oil and gas properties, (6) termination costs,
(7) gain on debt extinguishment, (8) write-off of debt issuance
costs, (9) interest expense, net, and (10) income tax
benefit. EBITDAX is not a measure of net income or cash flow as
determined by GAAP. The amounts included in the calculation of
EBITDAX were computed in accordance with GAAP. EBITDAX is presented
herein and reconciled to the GAAP measure of net loss because of
its wide acceptance by the investment community as a financial
indicator of a company's ability to internally fund development and
exploration activities. This measure is provided in addition to,
and not as an alternative for, and should be read in conjunction
with, the information contained in our financial statements
prepared in accordance with GAAP (including the notes), included in
our SEC filings and posted on our website.
The table below provides a reconciliation of EBITDAX to net loss
for the three and twelve months ended December 31, 2016 and 2015
(in thousands).
|
Three Months EndedDecember
31, |
|
Twelve Months EndedDecember
31, |
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
|
Net
loss |
$ |
(13,475 |
) |
|
$ |
(5,759 |
) |
|
$ |
(52,243 |
) |
|
$ |
(174,104 |
) |
Exploration |
|
685 |
|
|
|
228 |
|
|
|
3,923 |
|
|
|
4,439 |
|
Depletion, depreciation and amortization |
|
19,402 |
|
|
|
23,173 |
|
|
|
79,044 |
|
|
|
109,319 |
|
Share-based compensation |
|
1,998 |
|
|
|
1,954 |
|
|
|
6,279 |
|
|
|
7,954 |
|
Unrealized loss on commodity derivatives |
|
3,343 |
|
|
|
10,285 |
|
|
|
11,616 |
|
|
|
33,214 |
|
Impairment of oil and gas properties |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
220,197 |
|
Termination costs |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
1,436 |
|
Gain on
debt extinguishment |
|
– |
|
|
|
(9,080 |
) |
|
|
– |
|
|
|
(10,563 |
) |
Write-off
of debt issuance costs |
|
– |
|
|
|
– |
|
|
|
563 |
|
|
|
– |
|
Interest
expense, net |
|
7,086 |
|
|
|
6,436 |
|
|
|
27,259 |
|
|
|
25,066 |
|
Income
tax benefit |
|
(3,571 |
) |
|
|
(284 |
) |
|
|
(24,418 |
) |
|
|
(93,405 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX |
$ |
15,468 |
|
|
$ |
26,953 |
|
|
$ |
52,023 |
|
|
$ |
123,553 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Operating Expenses
We define cash operating expenses as operating expenses,
excluding (1) exploration expense, (2) depletion, depreciation and
amortization expense, (3) share-based compensation expense, (4)
termination costs, and (5) impairment of oil and gas properties.
Cash operating expenses is not a measure of operating expenses as
determined by GAAP. The amounts included in the calculation
of cash operating expenses were computed in accordance with
GAAP. Cash operating expenses is presented herein and
reconciled to the GAAP measure of operating expenses. We use
cash operating expenses as an indicator of the Company’s ability to
manage its operating expenses and cash flows. This measure is
provided in addition to, and not as an alternative for, and should
be read in conjunction with, the information contained in our
financial statements prepared in accordance with GAAP (including
the notes), included in our SEC filings and posted on our
website.
The table below provides a reconciliation of cash operating
expenses to operating expenses for the three and twelve months
ended December 31, 2016 and 2015 (in thousands, except per-Boe
amounts).
|
Three Months EndedDecember
31, |
|
Twelve Months EndedDecember
31, |
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
|
Operating
expenses |
$ |
33,564 |
|
|
$ |
38,671 |
|
|
$ |
135,168 |
|
|
$ |
403,789 |
|
Exploration |
|
(685 |
) |
|
|
(228 |
) |
|
|
(3,923 |
) |
|
|
(4,439 |
) |
Depletion, depreciation and amortization |
|
(19,402 |
) |
|
|
(23,173 |
) |
|
|
(79,044 |
) |
|
|
(109,319 |
) |
Share-based compensation |
|
(1,998 |
) |
|
|
(1,954 |
) |
|
|
(6,279 |
) |
|
|
(7,954 |
) |
Termination costs |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(1,436 |
) |
Impairment of oil and gas properties |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(220,197 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash operating
expenses |
$ |
11,479 |
|
|
$ |
13,316 |
|
|
$ |
45,922 |
|
|
$ |
60,444 |
|
Cash operating
expenses per Boe |
$ |
10.38 |
|
|
$ |
10.01 |
|
|
$ |
10.12 |
|
|
$ |
10.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10
The present value of our proved reserves, discounted at 10%
(“PV-10”), was estimated at $307.9 million at December 31, 2016,
and was calculated based on the first-of-the-month, 12-month
average prices for oil, NGLs and gas, of $42.69 per Bbl of oil,
$14.12 per Bbl of NGLs and $2.47 per MMBtu of natural gas price
during 2016, adjusted for basis differentials, grade and
quality.
PV-10 is our estimate of the present value of future net
revenues from proved oil and gas reserves after deducting estimated
production and ad valorem taxes, future capital costs and operating
expenses, but before deducting any estimates of future income
taxes. The estimated future net revenues are discounted at an
annual rate of 10% to determine their “present value.” We believe
PV-10 to be an important measure for evaluating the relative
significance of our oil and gas properties and that the
presentation of the non-GAAP financial measure of PV-10 provides
useful information to investors because it is widely used by
professional analysts and investors in evaluating oil and gas
companies. Because there are many unique factors that can impact an
individual company when estimating the amount of future income
taxes to be paid, we believe the use of a pre-tax measure is
valuable for evaluating the Company. We believe that PV-10 is a
financial measure routinely used and calculated similarly by other
companies in the oil and gas industry.
The table below reconciles PV-10 to our standardized measure of
discounted future net cash flows, the most directly comparable
measure calculated and presented in accordance with GAAP.
PV-10 should not be considered as an alternative to the
standardized measure as computed under GAAP.
(in
millions) |
|
December 31, 2016 |
|
PV-10 |
|
$ |
307.9 |
|
Less income taxes: |
|
|
|
|
Undiscounted future income taxes |
|
|
(132.8 |
) |
10%
discount factor |
|
|
122.7 |
|
Future
discounted income taxes |
|
|
(10.1 |
) |
|
|
|
|
|
Standardized measure of
discounted future net cash flows |
|
$ |
297.8 |
|
|
|
|
|
|
Liquidity
Liquidity is calculated by adding the net funds available under
our revolving credit facility and cash and cash equivalents.
We use liquidity as an indicator of the Company’s ability to fund
development and exploration activities. However, this
measurement has limitations. This measurement can vary from
year-to-year for the Company and can vary among companies based on
what is or is not included in the measurement on a company’s
financial statements. This measurement is provided in addition to,
and not as an alternative for, and should be read in conjunction
with, the information contained in our financial statements
prepared in accordance with GAAP (including the notes), included in
our SEC filings and posted on our website.
The table below summarizes our liquidity at December 31, 2016
and 2015 (in thousands).
|
Liquidity at December
31, |
|
|
2016 |
|
|
2015 |
|
Borrowing base |
$ |
325,000 |
|
|
$ |
450,000 |
|
Cash and
cash equivalents |
|
21 |
|
|
|
600 |
|
Senior secured credit
facility – outstanding borrowings |
|
(273,000 |
) |
|
|
(273,000 |
) |
Outstanding letters of
credit |
|
(575 |
) |
|
|
(325 |
) |
Liquidity |
$ |
51,446 |
|
|
$ |
177,275 |
|
|
|
|
|
|
|
|
|
Long-Term Debt-to-Capital
Long-term debt-to-capital ratio is calculated by dividing
long-term debt (GAAP) by the sum of total stockholders’ equity
(GAAP) and long-term debt (GAAP). We use the long-term
debt-to-capital ratio as a measurement of our overall financial
leverage. However, this ratio has limitations. This ratio can vary
from year-to-year for the Company and can vary among companies
based on what is or is not included in the ratio on a company’s
financial statements. This ratio is provided in addition to, and
not as an alternative for, and should be read in conjunction with,
the information contained in our financial statements prepared in
accordance with GAAP (including the notes), included in our SEC
filings and posted on our website.
The table below summarizes our long-term debt-to-capital ratio
at December 31, 2016 and 2015 (in thousands).
|
Long-Term Debt-to-Capital
at December 31, |
|
|
2016 |
|
|
2015 |
|
Long-term debt (1) |
$ |
498,349 |
|
|
$ |
496,587 |
|
Total
stockholders’ equity |
|
562,952 |
|
|
|
607,967 |
|
|
$ |
1,061,301 |
|
|
$ |
1,104,554 |
|
|
|
|
|
|
|
|
|
Long-term debt-to-capital |
|
47 |
% |
|
|
45 |
% |
|
|
|
|
|
|
|
|
(1) Long-term debt is net of debt issuance costs
of $5 million and $6.7 million at December 31, 2016 and December
31, 2015, respectively. |
|
INVESTOR CONTACT
Suzanne Ogle
Vice President Investor Relations & Corporate Communication
ir@approachresources.com
817.989.9000
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