Approach Resources Inc. (NASDAQ: AREX) today reported
financial and operational results for the fourth quarter and
full-year 2017 and estimated year-end 2017 proved reserves.
Fourth Quarter 2017 Highlights
- Fourth quarter production of 1,064 MBoe
or 11.6 MBoe/d
- Closed bolt-on acquisition increasing
our contiguous acreage position by approximately 39,000 net acres
and proved developed reserves of 1.6 MMBoe
- Extended term on revolving credit
facility to May 7, 2020, and reaffirmed $325 million borrowing
base
- Net income was $45.8 million, or $0.51
per diluted share. Adjusted net loss (non-GAAP) was $6.1 million,
or $0.07 per diluted share
- EBITDAX (non-GAAP) of $13.9
million
- Revenues of $28.4 million, an 11%
increase over the prior quarter
- Unhedged cash margin (non-GAAP) of
$15.76 per Boe, a 17% increase over the prior quarter
Full-Year 2017 Highlights
- Full year production of 4,232 MBoe or
11.6 MBoe/d, above the midpoint of annual guidance
- Year-end 2017 proved reserves 181.5
MMBoe, an increase of 16% over the prior year
- Type curve updated to 700 MBoe EUR, an
increase of 37%
- Strengthened balance sheet and reduced
the outstanding principal of our long-term debt by $127.1
million
- Increased operating cash flow by $11.4
million or 44% over the prior year
- 7% decrease in lease operating expense
(“LOE”) over the prior year, delivering record low annual LOE of
$4.23 per Boe
- Drilled 13 and completed nine
horizontal Wolfcamp wells during the year with an inventory of 10
drilled and uncompleted wells at year-end
- Reserve replacement ratio of 748%
- Net loss was $112.4 million, or $1.35
per diluted share. Adjusted net loss (non-GAAP) was $29.8 million,
or $0.36 per diluted share
- EBITDAX (non-GAAP) of $54.8 million, a
5% increase over the prior year
Adjusted net loss, EBITDAX and unhedged cash margin 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 income (loss) and unhedged cash margin to
revenues.
Management Comment
Ross Craft, Approach’s Chairman and CEO, commented, “In the face
of continued volatile commodity prices, in 2017 we delivered a
third consecutive year of fiscal discipline, optimizing returns and
providing steady production output. Our continued emphasis on cost
control and operating efficiency delivered industry-leading LOE, a
record low on a per Boe basis, despite double-digit service cost
escalation across the Permian Basin. Even with weather-related
operational restrictions during the year, we delivered solid
production, above the midpoint of annual guidance. We also
successfully completed a strategic exchange and follow-on exchange
of senior notes for equity and closed the Pangea West bolt-on
acquisition, adding production and HBP acreage in the highest oil
concentration of our core position. With 186 horizontal Wolfcamp
wells on line at year-end, we continue to demonstrate the
resilience of our asset, its suitability for manufacturing-style
development and the proficiency of our team as we exploit science
and technique to increase well recoveries and manage natural
production decline.
“We enter 2018 with our strategic objectives unchanged: deliver
a focused, disciplined capital program designed to maximize asset
value, maintain our industry-leading cost structure and seek
synergistic acquisition opportunities that will strengthen the
balance sheet and are accretive to per share metrics. By remaining
focused on our plan, we believe we are well positioned to create
value for our shareholders.”
Fourth Quarter 2017 Results
Production for fourth quarter 2017 totaled 1,064 MBoe (11.6
MBoe/d), made up of 25% oil, 36% NGLs and 39% natural gas. Average
realized commodity prices for fourth quarter 2017, before the
effect of commodity derivatives, were $52.09 per Bbl of oil, $22.61
per Bbl of NGLs and $2.32 per Mcf of natural gas. Our average
realized price, including the effect of commodity derivatives, was
$24.01 per Boe for fourth quarter 2017.
Net income for fourth quarter 2017 was $45.8 million, or $0.51
per diluted share, on revenues of $28.4 million. Net income for
fourth quarter 2017 included an income tax benefit of $51.9 million
related to the reduction in our deferred tax liabilities resulting
from the Tax Cuts and Jobs Act and an increase in the fair value of
our commodity derivatives of $1.4 million. Excluding these items,
adjusted net loss (non-GAAP) for fourth quarter 2017 was $6.1
million, or $0.07 per diluted share. EBITDAX (non-GAAP) for fourth
quarter 2017 was $13.9 million. See “Supplemental Non-GAAP
Financial and Other Measures” below for our reconciliation of
adjusted net loss and EBITDAX to net income.
LOE averaged $4.77 per Boe. Production and ad valorem taxes
averaged $2.09 per Boe, or 7.8% of oil, NGLs and gas sales.
Exploration costs were $0.38 per Boe. Total general and
administrative (“G&A”) costs averaged $5.16 per Boe, including
cash G&A costs of $4.09 per Boe. Depletion, depreciation and
amortization expense averaged $15.20 per Boe. Interest expense
totaled $5.4 million.
Full-Year 2017 Results
Production for 2017 was 4,232 MBoe (11.6 MBoe/d), made up of 26%
oil, 35% NGLs and 39% natural gas. Average realized commodity
prices for 2017, before the effect of commodity derivatives, were
$47.63 per Bbl of oil, $18.64 per Bbl of NGLs and $2.53 per Mcf of
natural gas. Our average realized price, including the effect of
commodity derivatives, was $23.86 per Boe for 2017.
Net loss for 2017 was $112.4 million, or $1.35 per diluted
share, on revenues of $105.3 million. Net loss for 2017 included a
write-off of $139.1 million of deferred tax assets in connection
with the completed debt for equity exchange transactions, an income
tax benefit of $51.9 million related to the reduction in our
deferred tax liabilities resulting from the Tax Cuts and Jobs Act,
a gain on debt extinguishment of $5.1 million and an increase in
the fair value of our commodity derivative of $4.1 million.
Excluding these items, adjusted net loss (non-GAAP) for 2017 was
$29.8 million, or $0.36 per diluted share. EBITDAX (non-GAAP) for
2017 was $54.8 million. See “Supplemental Non-GAAP Financial and
Other Measures” below for our reconciliation of adjusted net loss
and EBITDAX to net loss.
LOE averaged an annual record low of $4.23 per Boe. Production
and ad valorem taxes averaged $2.04 per Boe, or 8.2% of oil, NGLs
and gas sales. Exploration costs were $0.86 per Boe. Total G&A
costs averaged $5.75 per Boe, including cash G&A costs of $4.65
per Boe. Depletion, depreciation and amortization expense averaged
$16.66 per Boe. Interest expense totaled $21.1 million.
Operations Update
During the fourth quarter of 2017 we drilled one horizontal
Wolfcamp well to the A Bench in Pangea West. Currently, the well is
in flowback. In total, we completed four wells in the first quarter
of 2018 using our Generation X frac design and are very encouraged
by the early results of the wells. We hope to have additional
information to report in our next operations update.
In 2017, we focused on operating substantially within cash flow
and increasing activity in a disciplined manner in conjunction with
slowly recovering commodity prices. We maintained focus on managing
natural production decline through surface facility optimization,
operating efficiencies and investment in well repairs, workovers
and maintenance. During 2017, we drilled 13 horizontal Wolfcamp
wells. Of these, three wells were drilled to the A bench, five
wells were drilled to the B bench and five wells were drilled to
the C bench. We completed nine horizontal Wolfcamp wells. Of these,
one well was completed in the A bench, five wells were completed in
the B bench and three wells were completed in the C bench. The nine
completed wells are tracking at or above our 700 MBoe type curve,
wells normalized for a 7,500 foot lateral length. At December 31,
2017, we had 10 horizontal wells waiting on completion.
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
sustainable competitive advantages and environmentally responsible
facility operations. In 2017, by reducing resource consumption,
improving operating practices and minimizing ground transportation
we were able to maintain our industry leading LOE per Boe at
$4.23.
Innovation Drives Value
Our focus on driving value through a combination of innovation
and efficiency is evidenced in our GenX frac design, which balances
EUR improvement with cost control. The GenX frac design, first used
in 2015, has delivered significant well performance improvement in
our horizontal Wolfcamp wells while maintaining a competitive
drilling cost. As a result, Approach raised its type curve to an
EUR of 700 MBoe to reflect the improved productivity, an increase
of 37%.
Fourth Quarter and Full-Year 2017 Production
Fourth quarter 2017 production totaled 1,064 MBoe (11.6 MBoe/d).
Full-year 2017 production totaled 4,232 MBoe (11.6 MBoe/d).
Three and 12 Months Ended December 31,
2017 Three months 12 months
Production: Oil (MBbls) 270 1,107 NGLs (MBbls) 377 1,486 Gas
(MMcf) 2,498 9,829 Total (MBoe) 1,064 4,232 Total (Mboe/d) 11.6
11.6
2017 Estimated Proved Reserves and Costs Incurred
Year-end 2017 proved reserves totaled 181.5 MMBoe. Year-end 2017
proved reserves were 28% oil, 32% NGLs and 40% natural gas. Proved
developed reserves represent approximately 37% of total year-end
2017 proved reserves.
At December 31, 2017, substantially all of our proved reserves
were located in our core operating area in the southern Midland
Basin. Year-end 2017 estimated proved reserves included 170.2 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, 2017, 2016,
and 2015.
Years Ended December 31, 2017
2016 2015 Horizontal
Wolfcamp Proved developed 55,032 47,861 49,843 Proved
undeveloped 115,146 97,502 104,790 Total
170,178 145,363 154,633 Percent of total proved reserves 94 % 93 %
93 %
Other Vertical Proved developed 11,368 11,014
12,013 Percent of total proved reserves 6 % 7 % 7 %
Total proved reserves 181,546 156,377
166,646
Extensions and discoveries for 2017 were 33.3 MMBoe, primarily
attributable to our development project in the Wolfcamp shale oil
resource play in the Permian Basin. During 2017, we acquired 1.6
MMBoe of proved reserves through the bolt-on acquisition, and we
reclassified 17.7 MMBoe of proved undeveloped reserves to unproved
reserves. The reserves reclassified are attributable to horizontal
well locations in Project Pangea that are no longer expected to be
developed within five years from their initial booking, as required
by SEC rules. Revisions included an increase of 9.4 MMBoe resulting
from updated well performance and technical parameters, and an
increase of 3.1 MMBoe due to higher commodity prices.
The following table summarizes the changes in our estimated
proved reserves during 2017.
Oil NGLs
Natural Gas Total (MBbls)
(MBbls) (MMcf) (MBoe) Balance — December
31, 2016 50,031 47,634 352,277 156,377 Extensions and
discoveries 10,546 9,975 76,709 33,307 Acquisition of minerals in
place 710 394 2,808 1,572 Production(1) (1,107 ) (1,486 ) (11,148 )
(4,452 ) Revisions to previous estimates (10,120 ) 1,431
20,582 (5,259 )
Balance — December 31, 2017 50,060
57,948 441,228 181,545
Reserve replacement ratio Extensions and discoveries /
Production 748 %
(1) Production includes 1,319 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,
2017, was $460.8 million. The PV-10 (non-GAAP), or pre-tax present
value of our proved reserves discounted at 10%, of our proved
reserves at December 31, 2017, was $521 million ($582.2 million at
December 31, 2017, NYMEX strip).
The independent engineering firm DeGolyer and MacNaughton
prepared our estimates of year-end 2017 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 $51.34 per Bbl of oil, $18.67 per
Bbl of NGLs and $2.99 per MMBtu of natural gas during 2017.
At NYMEX strip pricing at December 31, 2017, PV-10 is $582.2
million. The following table summarizes the NYMEX strip prices at
December 31, 2017.
2018 2019
2020 2021 2022(1)
Oil (per Bbl) $ 59.55 $ 56.19 $ 53.76 $ 52.29 $ 51.67 Natural gas
(per MMBtu) $ 2.84 $ 2.81 $ 2.82 $ 2.85 $ 2.89 (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.
Capital Expenditures
Fourth quarter capital expenditures were $1.3 million. Net
capital expenditures incurred during 2017 totaled $47.1 million and
were attributable to drilling and development ($44.2 million),
infrastructure projects and equipment ($3.6 million) and acreage
extensions ($0.2 million), partially offset by a sales tax refund
of $0.9 million.
Liquidity Update
At December 31, 2017, we had a $1 billion senior secured
revolving credit facility in place with a borrowing base of $325
million, and liquidity of $33.7 million. See “Supplemental Non-GAAP
Financial and Other Measures” below for our definition and
calculation of liquidity.
Commodity Derivatives Update
We enter into commodity derivatives positions to reduce the risk
of commodity price fluctuations. At present, approximately 52% of
2018 forecasted oil, 55% of 2018 forecasted natural gas and 50% of
NGL production is hedged. The table below is a summary of our
current derivatives positions.
Contract
Commodity and Period Type Volume Transacted
Contract Price Crude Oil January 2018 — December 2018
Swap 300 Bbls/day $50.00/Bbl January 2018 — March 2018 Collar 1,000
Bbls/day $50.00/Bbl - $55.05/Bbl January 2018 — June 2018 Collar
500 Bbls/day $55.00/Bbl - $60.00/Bbl January 2018 — September 2018
Swap 700 Bbls/day $60.50/Bbl April 2018 — September 2018 Swap 800
Bbls/day $60.50/Bbl
Natural Gas 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 2018 — December 2018 Swap 1,000 Bbls/day
$11.424/Bbl
NGLs (C3 - Propane) January 2018 — March 2018
Swap 450 Bbls/day $30.24/Bbl February 2018 — December 2018 Swap 600
Bbls/day $32.991/Bbl
NGLs (IC4 - Isobutane) January 2018 —
March 2018 Swap 50 Bbls/day $36.12/Bbl February 2018 — December
2018 Swap 50 Bbls/day $38.262/Bbl
NGLs (NC4 - Butane)
January 2018 — March 2018 Swap 150 Bbls/day $35.70/Bbl February
2018 — December 2018 Swap 200 Bbls/day $38.22/Bbl
NGLs (C5 -
Pentane) January 2018 — December 2018 Swap 200 Bbls/day
$56.364/Bbl
Guidance
The Company’s capital budget for 2018 is a range of $50 million
to $70 million, depending on commodity prices. The table below sets
forth our production and operating costs and expenses guidance for
2018.
2018 Guidance Capital Expenditures (in
millions) $50 − $70
Production: Oil (MBbls) 1,150
− 1,250 NGLs (MBbls) 1,450 − 1,550 Gas (MMcf) 9,600 − 10,200 Total
(MBoe) 4,200 − 4,500
Cash operating costs (per Boe):
Lease operating $4.50 − 5.50 Production and ad valorem taxes 8.25%
of oil and gas revenues Cash general and administrative $4.50 −
5.50
Non-cash operating costs (per Boe): Non-cash general
and administrative $0.50 − 1.00 Exploration $0.50 − 1.00 Depletion,
depreciation and amortization $16.00 − 17.00
First quarter 2018 production is estimated to be approximately
11.3 MBoe/d. First quarter 2018 production will be affected by no
new well completions in the fourth quarter of 2017 and weather.
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 2018 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.
Conference Call Information and Summary Presentation
The Company will host a conference call on Friday, March 9,
2018, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to
discuss fourth quarter and full-year 2017 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: 4883409
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: 4883409
In addition, a fourth quarter and full-year 2017 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 Ended
Twelve Months Ended December 31, December 31,
2017 2016 2017
2016 Revenues (in thousands): Oil $ 14,082 $ 14,007 $
52,748 $ 48,311 NGLs 8,530 5,798 27,702 19,761 Gas 5,805
6,700 24,899 22,230 Total oil,
NGLs and gas sales 28,417 26,505 105,349 90,302 Net cash (payment)
receipt on derivative settlements (2,878 ) 442
(4,359 ) 6,132
Total oil, NGLs and gas sales including
derivative impact
$ 25,539 $ 26,947 $ 100,990 $ 96,434
Production: Oil (MBbls) 270 304 1,107 1,275 NGLs (MBbls) 377
380 1,486 1,529 Gas (MMcf) 2,498 2,530
9,829 10,404 Total (MBoe) 1,064 1,106 4,232 4,537
Total (MBoe/d) 11.6 12.0 11.6 12.4
Average prices: Oil (per
Bbl) $ 52.09 $ 46.02 $ 47.63 $ 37.90 NGLs (per Bbl) 22.61 15.25
18.64 12.93 Gas (per Mcf) 2.32 2.65
2.53 2.14 Total (per Boe) $ 26.71 $ 23.96 $ 24.89 $
19.90 Net cash (payment) receipt on derivative settlements (per
Boe) (2.70 ) 0.40 (1.03 ) 1.35 Total
including derivative impact (per Boe) $ 24.01 $ 24.36 $ 23.86 $
21.25
Costs and expenses (per Boe): Lease operating $ 4.77 $
3.40 $ 4.23 $ 4.24 Production and ad valorem taxes 2.09 2.43 2.04
1.81 Exploration 0.38 0.62 0.86 0.86 General and administrative (1)
5.16 6.35 5.75 5.45 Depletion, depreciation and amortization 15.20
17.54 16.66 17.42 (1) Below is a summary of general and
administrative expense: General and administrative - cash component
$ 4.09 $ 4.55 $ 4.65 $ 4.07 General and administrative - noncash
component (share-based compensation) 1.07 1.80 1.10 1.38
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, 2017
2016 2017
2016 REVENUES: Oil, NGLs
and gas sales $ 28,417 $ 26,505 $ 105,349 $ 90,302
EXPENSES:
Lease operating 5,076 3,766 17,902 19,250 Production and ad valorem
taxes 2,219 2,685 8,644 8,217 Exploration 406 685 3,657 3,923
General and administrative 5,491 7,026 24,333 24,734 Depletion,
depreciation and amortization 16,173 19,402
70,521 79,044 Total expenses
29,365 33,564 125,057
135,168
OPERATING LOSS (948 ) (7,059 ) (19,708
) (44,866 )
OTHER: Interest expense, net (5,370 ) (7,086 )
(21,053 ) (27,259 ) Gain on debt extinguishment — — 5,053 —
Write-off of debt issuance costs — — — (563 ) Commodity derivative
(loss) gain (1,377 ) (2,901 ) (262 ) (5,484 ) Other income —
— 32 1,511
LOSS BEFORE INCOME TAX (BENEFIT)
PROVISION
(7,695 ) (17,046 ) (35,938 ) (76,661 )
INCOME TAX (BENEFIT) PROVISION:
Current — — (66 ) — Deferred (53,512 ) (3,571 )
76,487 (24,418 )
NET INCOME (LOSS) $
45,817 $ (13,475 ) $ (112,359 ) $ (52,243 )
EARNINGS
(LOSS) PER SHARE: Basic $ 0.51 $ (0.32 ) $ (1.35 ) $
(1.26 ) Diluted $ 0.51 $ (0.32 ) $ (1.35 ) $ (1.26 )
WEIGHTED AVERAGE SHARES OUTSTANDING: Basic 90,114,659
41,705,462 83,404,104 41,488,206 Diluted 90,114,659 41,705,462
83,404,104 41,488,206
UNAUDITED SELECTED FINANCIAL
DATA
Unaudited Consolidated Balance Sheet
Data December 31, (in
thousands) 2017 2016 Cash and cash
equivalents $ 21 $ 21 Other current assets 16,679 12,473 Property
and equipment, net, successful efforts method 1,082,876
1,092,061 Total assets $ 1,099,576 $ 1,104,555
Current liabilities $ 25,067 $ 26,369 Long-term debt (1) 373,460
498,349 Deferred income taxes 82,102 5,615 Other long-term
liabilities 11,531 11,270 Stockholders' equity 607,416
562,952 Total liabilities and stockholders' equity $
1,099,576 $ 1,104,555 (1) Long-term debt at December 31,
2017, is comprised of $85.2 million in 7% senior notes due 2021 and
$291 million in outstanding borrowings under our revolving credit
facility, net of issuance costs of $1.1 million and $1.7 million,
respectively. 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 revolving credit facility, net of
issuance costs of $3.7 million and $1.3 million, respectively.
Unaudited Consolidated Cash Flow
Data Year Ended December 31, (in
thousands) 2017
2016 Net cash provided by (used in): Operating
activities $ 37,454 $ 26,081 Investing activities (52,409 ) (23,890
) Financing activities 14,955 (2,770 )
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 excludes
(1) non-cash fair value (gain) loss on commodity derivatives, (2)
gain on debt extinguishment, (3) write-off of debt issuance costs,
(4) write-off of deferred tax assets, (5) acquisition related
costs, (6) tax benefit related to federal tax law change, and (6)
related income tax effect on adjustments and other discrete tax
items. 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 income (loss) for the three and twelve months ended December
31, 2017 and 2016 (in thousands, except per-share amounts).
Three Months Ended Twelve
Months Ended December 31, December 31,
2017 2016
2017 2016 Net
income (loss) $ 45,817 $ (13,475 ) $ (112,359 ) $ (52,243 )
Adjustments for certain items: Non-cash fair value (gain)
loss on derivatives (1,500 ) 3,343 (4,097 ) 11,616 Gain on debt
extinguishment — — (5,053 ) — Write-off of debt issuance costs — —
— 563 Write-off of deferred tax assets — — 139,090 — Acquisition
related costs 110 110 Tax benefit related to change in federal tax
law (51,939 ) — (51,939 ) — Tax effect and other discrete tax items
(1) 1,446 401 4,443
(2,437 )
Adjusted net loss $ (6,066 ) $ (9,731
) $ (29,805 ) $ (42,501 )
Adjusted net loss per diluted
share $ (0.07 ) $ (0.23 ) $ (0.36 ) $ (1.02 )
(1) The estimated income tax impacts on adjustments to net income
(loss) are computed based upon a statutory rate of 35%, applicable
to all periods presented. Additionally, this includes the tax
impact of a tax shortfall related to share-based compensation of $1
million, and $1.6 million for the three months ended December 31,
2017, and December 31, 2016, respectively; and $1.3 million and
$1.8 million for the years ended December 31, 2017, and December
31, 2016, respectively.
EBITDAX
We define EBITDAX as net income (loss), plus (1) exploration
expense, (2) depletion, depreciation and amortization expense, (3)
share-based compensation expense, (4) non-cash fair value (gain)
loss on derivatives, (5) gain on debt extinguishment, (6) write-off
of debt issuance costs, (7) interest expense, net, and (8) 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 income (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
income (loss) for the three and twelve months ended December 31,
2017 and 2016 (in thousands).
Three Months Ended Twelve
Months Ended December 31, December 31,
2017 2016
2017 2016 Net
income (loss) $ 45,817 $ (13,475 ) $ (112,359 ) $ (52,243 )
Exploration 406 685 3,657 3,923 Depletion, depreciation and
amortization 16,173 19,402 70,521 79,044 Share-based compensation
1,138 1,998 4,656 6,279 Non-cash fair value (gain) loss on
derivatives (1,500 ) 3,343 (4,097 ) 11,616 Gain on debt
extinguishment — — (5,053 ) — Write-off of debt issuance costs — —
— 563 Interest expense, net 5,370 7,086 21,053 27,259 Income tax
(benefit) provision (53,512 ) (3,571 ) 76,421
(24,418 )
EBITDAX $ 13,892 $
15,468 $ 54,799 $ 52,023
Unhedged Cash Margin and Cash Operating Expenses
We define unhedged cash margin as revenue, less cash operating
expenses. We define cash operating expenses as operating expenses,
excluding (1) exploration expense, (2) depletion, depreciation and
amortization expense, and (3) share-based compensation expense.
Unhedged cash margin and cash operating expenses are not measures
of operating income or cash flows as determined by GAAP. The
amounts included in the calculations of unhedged cash margin and
cash operating expenses were computed in accordance with GAAP.
Unhedged cash margin and cash operating expenses are presented
herein and reconciled to the GAAP measures of revenue and operating
expenses. We use unhedged cash margin and cash operating expenses
as an indicator of the Company’s profitability and ability to
manage its operating income 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 unhedged cash
margin and cash operating expenses to revenues and operating
expenses for the three and twelve months ended December 31, 2017
and 2016 (in thousands, except per-Boe amounts).
Three Months Ended Twelve
Months Ended December 31, December 31,
2017 2016
2017 2016
Revenues $ 28,417 $ 26,505 $ 105,349 $ 90,302
Production
(Mboe) 1,064 1,106 4,232 4,537
Average realized price (per
Boe) $ 26.71 $ 23.96 $ 24.89 $ 19.90
Operating
expenses $ 29,365 $ 33,564 $ 125,057 $ 135,168 Exploration (406
) (685 ) (3,657 ) (3,923 ) Depletion, depreciation and amortization
(16,173 ) (19,402 ) (70,521 ) (79,044 ) Share-based compensation
(1,138 ) (1,998 ) (4,656 ) (6,279 )
Cash operating expenses $ 11,648 $ 11,479 $ 46,223 $ 45,922
Cash operating expenses per Boe $ 10.95 $ 10.38
$ 10.92 $ 10.12
Unhedged cash
margin $ 16,769 $ 15,026 $ 59,126 $ 44,380
Unhedged cash
margin per Boe $ 15.76 $ 13.58 $ 13.97 $
9.78
PV-10
The present value of our proved reserves, discounted at 10%
(“PV-10”), was estimated at $521 million at December 31, 2017, and
was calculated based on the first-of-the-month, 12-month average
prices for oil, NGLs and gas, of $51.34 per Bbl of oil, $18.67 per
Bbl of NGLs and $2.99 per MMBtu of natural gas price during 2017,
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, 2017 PV-10 $
521.0 Less income taxes: Undiscounted future income taxes (323.3 )
10% discount factor 263.3 Future discounted income
taxes (60.0 ) Standardized measure of discounted
future net cash flows $ 461.0
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, 2017
and 2016 (in thousands).
Year Ended December 31, 2017
2016 Credit Facility
commitments $ 325,000 $ 325,000 Cash and cash equivalents 21 21
Long-term debt — Credit Facility (291,000 ) (273,000 ) Undrawn
letters of credit (325 ) (575 ) Liquidity $ 33,696
$ 51,446
View source
version on businesswire.com: http://www.businesswire.com/news/home/20180308006406/en/
Approach Resources Inc.Suzanne Ogle, 817-989-9000Vice President
– Investor Relations & Corporate
Communicationsir@approachresources.com
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