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23:35 | 08.03.2018
Approach Resources Inc. Reports Fourth Quarter and Full-Year 2017 Financial and Operating Results and Provides 2018 Outlook

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 monthsProduction:

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
 

 
2015Horizontal 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 PriceCrude 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 GuidanceCapital 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 ResourcesApproach 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
 

 
2016Revenues (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 SUBSIDIARIESUNAUDITED 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/


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