Item 2. Management’s Discussion and Analysis of Financial Condition and Res
ults of Operations.
The following discussion is intended to assist in understanding our results of operations and our financial condition. This section should be read in conjunction with management’s discussion and analysis contained in our Annual Report on Form 10-K for the year ended December 31, 2016, filed with the Securities and Exchange Commission (“SEC”) on March 10, 2017. Our consolidated financial statements and the accompanying notes included elsewhere in this report contain additional information that should be referred to when reviewing this material. Certain statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed in this report. A glossary containing the meaning of the oil and gas industry terms used in this management’s discussion and analysis follows the “Results of Operations” table in this Item 2.
Cautionary Statement Regarding Forward-Looking Statements
Various statements in this report, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The forward-looking statements may include projections and estimates concerning the timing and success of specific projects, typical well economics and our future reserves, production, revenues, costs, income, capital spending, 3-D seismic operations, interpretation and results and obtaining permits and regulatory approvals. When used in this report, the words “will,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” “potential” 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.
These forward-looking statements are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. We caution all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed or referred to in the “Risk Factors” section and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We disclaim any obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, unless required by law. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:
|
•
|
uncertainties in drilling, exploring for and producing oil and gas;
|
|
•
|
oil, NGLs and natural gas prices;
|
|
•
|
overall United States and global economic and financial market conditions;
|
|
•
|
our leverage negatively affecting our semi-annual redetermination of our revolving credit facility;
|
|
•
|
domestic and foreign demand and supply for oil, NGLs, natural gas and the products derived from such hydrocarbons;
|
|
•
|
actions of the Organization of Petroleum Exporting Countries, its members and other state-controlled oil companies relating to oil price and production controls;
|
|
•
|
our ability to obtain additional financing necessary to fund our operations and capital expenditures and to meet our other obligations;
|
|
•
|
our ability to maintain a sound financial position;
|
|
•
|
our cash flows and liquidity;
|
|
•
|
the effects of government regulation and permitting and other legal requirements, including laws or regulations that could restrict or prohibit hydraulic fracturing;
|
|
•
|
disruption of credit and capital markets;
|
|
•
|
disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil, NGLs and natural gas and other processing and transportation considerations;
|
|
•
|
marketing of oil, NGLs and natural gas;
|
12
|
•
|
high costs, shortages, delivery delays or unavailability of drilling and completion equipment, materials, labor or other services;
|
|
•
|
competition in the oil and gas industry;
|
|
•
|
uncertainty regarding our future operating results;
|
|
•
|
profitability of drilling locations;
|
|
•
|
interpretation of 3-D seismic data;
|
|
•
|
replacing our oil, NGLs and natural gas reserves;
|
|
•
|
our ability to retain and attract key personnel;
|
|
•
|
our business strategy, including our ability to recover oil, NGLs and natural gas in place associated with our Wolfcamp shale oil resource play in the Permian Basin;
|
|
•
|
development of our current asset base or property acquisitions;
|
|
•
|
estimated quantities of oil, NGLs and natural gas reserves and present value thereof;
|
|
•
|
plans, objectives, expectations and intentions contained in this report that are not historical; and
|
|
•
|
other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on March 10, 2017.
|
Overview
Approach Resources Inc. is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas reserves in the Midland Basin of the greater Permian Basin in West Texas, where we leased approximately 114,000 net acres as of June 30, 2017. We believe our concentrated acreage position and extensive, integrated field infrastructure system provides us an opportunity to achieve cost, operating and recovery efficiencies in the development of our drilling inventory.
Our long-term business strategy is to create value by growing reserves and production in a cost efficient manner and at attractive rates of return. We intend to pursue that strategy by developing resource potential from the Wolfcamp shale oil formation and pursuing acquisitions that meet our strategic and financial objectives.
Additional drilling targets could include the Clearfork, Canyon Sands, Strawn and Ellenburger zones. We sometimes refer to our development project in the Permian Basin as “Project Pangea,” which includes “Pangea West.” Our management and technical team have a proven track record of finding and developing reserves through advanced drilling and completion techniques. As the operator of all of our estimated proved reserves and production, we have a high degree of control over capital expenditures and other operating matters.
At December 31, 2016, our estimated proved reserves were 156.4 million barrels of oil equivalent (“MMBoe”), made up of 32% oil, 30% NGLs and 38% gas. The proved developed reserves were 38% of our total proved reserves at December 31, 2016. Substantially all of our proved reserves are located in the Permian Basin in Crockett and Schleicher counties, Texas. At June 30, 2017, we owned working interests in 807 producing oil and gas wells.
In the first quarter of 2017, we completed two debt for equity exchanges
(together, the “Exchange Transactions”), which reduced the principal amount of our outstanding 7% Senior Notes due 2021 (“Senior Notes”) by $145.1 million, and interest payments by $44.3 million over the remaining term of the Senior Notes. The Exchange Transactions provide us the flexibility to use the interest savings to invest in our capital budget, to
continue to reduce long-term debt or for other corporate purposes.
Second Quarter 2017 Activity
During the three months ended June 30, 2017, we produced 1,080 MBoe, or 11.9 MBoe/d, and increased production 4%, compared to the three months ended March 31, 2017. During the quarter, we drilled eight horizontal wells and completed five horizontal wells. At June 30, 2017, we had one horizontal rig running in Project Pangea, which we released in mid-July, ten horizontal Wolfcamp wells waiting on completion and one well being drilled.
2017 Capital Expenditures
For the three months ended June 30, 2017, our capital expenditures totaled $24.4 million, consisting of $23.8 million for drilling and completion activities and $1.5 million for infrastructure projects and equipment, partially offset by a sales tax refund of $0.9 million. For the six months ended June 30, 2017, our capital expenditures totaled $37.8 million, consisting of $35.9 million for drilling
13
and completion activities and $
2.
8
million for infrastructure projects and equipment, partially offset by a sales tax refund of $0.9 million.
Our 2017 capital budget is a range of $50 million to $70 million.
W
e have increased our expected capital budget in 2017 compared to our 2016 capital budget in response to interest savings from the Exchange Transactions and increased commodity prices. We will continue to monitor commodity prices, which may affect our capital budget and production for the remainder of 2017.
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 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. Although the impact of changes in these collective factors in a sustained, low commodity price environment is difficult to estimate, we currently expect to execute our development plan based on current conditions. To the extent there is a significant increase or decrease in commodity prices in the future, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan.
14
Results of Operations
The following table sets forth summary information regarding oil, NGLs and gas revenues, production, average product prices and average production costs and expenses for the three and six months ended June 30, 2017 and 2016. We determine a barrel of oil equivalent using the ratio of six Mcf of natural gas to one Boe, and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas or NGLs may differ significantly from the price for a barrel of oil.
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
12,508
|
|
|
$
|
12,556
|
|
|
$
|
26,202
|
|
|
$
|
22,243
|
|
NGLs
|
|
|
6,019
|
|
|
|
5,497
|
|
|
|
12,079
|
|
|
|
8,721
|
|
Gas
|
|
|
6,442
|
|
|
|
4,380
|
|
|
|
13,043
|
|
|
|
9,084
|
|
Total oil, NGLs and gas sales
|
|
|
24,969
|
|
|
|
22,433
|
|
|
|
51,324
|
|
|
|
40,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain (loss) on commodity derivatives
|
|
|
3
|
|
|
|
1,409
|
|
|
|
(958
|
)
|
|
|
4,909
|
|
Total oil, NGLs and gas sales including derivative
impact
|
|
$
|
24,972
|
|
|
$
|
23,842
|
|
|
$
|
50,366
|
|
|
$
|
44,957
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
281
|
|
|
|
315
|
|
|
|
560
|
|
|
|
673
|
|
NGLs (MBbls)
|
|
|
383
|
|
|
|
392
|
|
|
|
735
|
|
|
|
755
|
|
Gas (MMcf)
|
|
|
2,499
|
|
|
|
2,644
|
|
|
|
4,875
|
|
|
|
5,317
|
|
Total (MBoe)
|
|
|
1,080
|
|
|
|
1,148
|
|
|
|
2,107
|
|
|
|
2,314
|
|
Total (MBoe/d)
|
|
|
11.9
|
|
|
|
12.6
|
|
|
|
11.6
|
|
|
|
12.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
44.50
|
|
|
$
|
39.84
|
|
|
$
|
46.83
|
|
|
$
|
33.07
|
|
NGLs (per Bbl)
|
|
|
15.72
|
|
|
|
14.00
|
|
|
|
16.43
|
|
|
|
11.55
|
|
Gas (per Mcf)
|
|
|
2.58
|
|
|
|
1.66
|
|
|
|
2.68
|
|
|
|
1.71
|
|
Total (per Boe)
|
|
|
23.11
|
|
|
|
19.53
|
|
|
|
24.36
|
|
|
|
17.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain (loss) on commodity derivatives (per Boe)
|
|
|
—
|
|
|
|
1.23
|
|
|
|
(0.46
|
)
|
|
|
2.12
|
|
Total including derivative impact (per Boe)
|
|
$
|
23.11
|
|
|
$
|
20.76
|
|
|
$
|
23.90
|
|
|
$
|
19.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses (per Boe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
3.92
|
|
|
$
|
4.56
|
|
|
$
|
3.99
|
|
|
$
|
5.01
|
|
Production and ad valorem taxes
|
|
|
2.09
|
|
|
|
1.62
|
|
|
|
2.19
|
|
|
|
1.52
|
|
Exploration
|
|
|
1.95
|
|
|
|
1.41
|
|
|
|
1.50
|
|
|
|
0.95
|
|
General and administrative
|
|
|
6.06
|
|
|
|
5.08
|
|
|
|
5.92
|
|
|
|
5.14
|
|
Depletion, depreciation and amortization
|
|
|
18.09
|
|
|
|
17.41
|
|
|
|
17.80
|
|
|
|
17.38
|
|
Glossary
Bbl.
One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to reference oil, condensate or NGLs.
Boe.
Barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil equivalent, and one Bbl of NGLs to one Bbl of oil equivalent.
MBbl.
Thousand barrels of oil, condensate or NGLs.
MBoe.
Thousand barrels of oil equivalent.
Mcf.
Thousand cubic feet of natural gas.
MMBoe.
Million barrels of oil equivalent.
15
MMBtu.
Million British thermal units.
MMcf.
Million cubic feet of natural gas.
NGLs.
Natural gas liquids.
NYMEX.
New York Mercantile Exchange.
/d.
“Per day” when used with volumetric units or dollars.
Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016
Oil, NGLs and gas sales
. Oil, NGLs and gas sales increased $2.6 million, or 11%, for the three months ended June 30, 2017, to $25 million, compared to $22.4 million for the three months ended June 30, 2016. The increase in oil, NGLs and gas sales was due to an increase in average realized commodity prices ($3.9 million), partially offset by a decrease in production volumes ($1.3 million). Production volumes decreased as a result of reduced drilling and completion activity in 2016.
Net loss
. Net loss for the three months ended June 30, 2017, was $ 8.9 million, or $0.10 per diluted share, compared to $16 million, or $0.39 per diluted share, for the three months ended June 30, 2016. Net loss for the three months ended June 30, 2017, included an unrealized gain on commodity derivatives of $1.2 million. The decrease in the net loss for the three months ended June 30, 2017, was primarily due to an increase in the unrealized gain on commodity derivatives ($9.3 million), an increase in revenues ($2.6 million), and a decrease in interest expense ($1.9 million) due to the Exchange Transactions, partially offset by a decrease in the realized gain on commodity derivatives ($1.4 million) and a decrease in other income ($1.4 million).
Oil, NGLs and gas production.
Production for the three months ended June 30, 2017, totaled 1,080 MBoe (11.9 MBoe/d), compared to production of 1,148 MBoe (12.6 MBoe/d) in the prior-year period, a 6% decrease. Production for the three months ended June 30, 2017, was 26% oil, 35% NGLs and 39% gas, compared to 28% oil, 34% NGLs and 38% gas in the 2016 period. Production volumes decreased during the three months ended June 30, 2017, as a result of reduced drilling and completion activity in 2016.
Commodity derivative activities.
Our commodity derivative activity resulted in realized gains of $3,000 and $1.4 million for the three months ended June 30, 2017 and 2016, respectively. Our average realized price, including the effect of commodity derivatives, was $23.11 per Boe for the three months ended June 30, 2017, compared to $20.76 per Boe for the three months ended June 30, 2016. Realized gains and losses on commodity derivatives are derived from the relative movement of commodity prices in relation to the fixed notional pricing of our derivatives contracts for the respective periods. The unrealized gain on commodity derivatives was $1.2 million for the three months ended June 30, 2017, compared to an unrealized loss of $8.1 million for the three months ended June 30, 2016. As commodity prices increase or decrease, the fair value of the open portion of those positions decreases or increases, respectively.
Historically, we have not designated our derivative instruments as cash-flow hedges. We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized gain (loss) on commodity derivatives.”
Lease operating.
Our lease operating expenses (“LOE”) decreased $1 million, or 19%, for the three months ended June 30, 2017, to $4.2 million, or $3.92 per Boe, compared to $5.2 million, or $4.56 per Boe, for the three months ended June 30, 2016. The decrease in LOE per Boe for the three months ended June 30, 2017, was primarily due to increased efficiency in our water handling operations, a decrease in compressor rental and repair and a decrease in well repairs, workovers and maintenance, partially offset by a decrease in production volumes and an increase in pumpers and supervision costs. The following table summarizes LOE per Boe.
|
|
Three Months Ended
June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
|
|
|
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
% Change (Boe)
|
|
Compressor rental and repair
|
|
$
|
1.7
|
|
|
$
|
1.59
|
|
|
$
|
2.0
|
|
|
$
|
1.73
|
|
|
$
|
(0.3
|
)
|
|
$
|
(0.14
|
)
|
|
|
(8.1
|
)%
|
Well repairs, workovers and maintenance
|
|
|
0.9
|
|
|
|
0.85
|
|
|
|
1.0
|
|
|
|
0.92
|
|
|
|
(0.1
|
)
|
|
|
(0.07
|
)
|
|
|
(7.6
|
)
|
Water handling and other
|
|
|
0.8
|
|
|
|
0.76
|
|
|
|
1.5
|
|
|
|
1.30
|
|
|
|
(0.7
|
)
|
|
|
(0.54
|
)
|
|
|
(41.5
|
)
|
Pumpers and supervision
|
|
|
0.8
|
|
|
|
0.72
|
|
|
|
0.7
|
|
|
|
0.61
|
|
|
|
0.1
|
|
|
|
0.11
|
|
|
|
18.0
|
|
Total
|
|
$
|
4.2
|
|
|
$
|
3.92
|
|
|
$
|
5.2
|
|
|
$
|
4.56
|
|
|
$
|
(1.0
|
)
|
|
$
|
(0.64
|
)
|
|
|
(14.0
|
)%
|
16
Production and ad valorem taxes.
Our production and ad valorem taxes increased $0.4 million, or 21%, for the three months ended June 30, 2017, to $2.3 million compared to $1.9 million for the three months ended June 30, 2016. Production and ad valorem taxes were $2.09 per Boe and $1.62 per Boe and approximately 9% and 8.3% of oil, NGLs and gas sales for the three months ended June 30, 2017 and 2016, respectively. The increase in production and ad valorem taxes was primarily a function of the increase in oil, NGLs and gas sales between the two periods.
Exploration.
We recorded $2.1 million, or $1.95 per Boe, and $1.6 million, or $1.41 per Boe, of exploration expense for the three months ended June 30, 2017 and 2016, respectively. The majority of exploration expense is non-cash and relates to lease expirations. The increase in exploration expense was primarily due to an increase in lease expirations in the second quarter of 2017. We expect exploration expense to decrease for the remainder of 2017.
General and administrative
. Our general and administrative expenses (“G&A”) increased $0.7 million, or 12%, to $6.5 million, or $6.06 per Boe, for the three months ended June 30, 2017, compared to $5.8 million, or $5.08 per Boe, for the three months ended June 30, 2016. The increases in G&A and G&A per Boe were primarily due to an increase in salaries and benefits, professional fees, and lower production volumes, partially offset by a decrease in share-based compensation. For the three months ended June 30, 2017,
G&A included $0.4 million in expense related to cash-settled performance awards, compared to $0.3 million for the three months ended June 30, 2016. These awards are re-measured each interim reporting period based on the fair market value of our common stock. Significant changes in the fair market value of our common stock will impact G&A per Boe.
The following table summarizes G&A in millions and G&A per Boe.
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
|
|
|
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
% Change (Boe)
|
|
Salaries and benefits
|
|
$
|
3.6
|
|
|
$
|
3.36
|
|
|
$
|
2.9
|
|
|
$
|
2.55
|
|
|
$
|
0.7
|
|
|
$
|
0.81
|
|
|
|
31.8
|
%
|
Share-based compensation
|
|
|
1.0
|
|
|
$
|
0.95
|
|
|
|
1.4
|
|
|
$
|
1.20
|
|
|
|
(0.4
|
)
|
|
|
(0.25
|
)
|
|
|
(20.8
|
)
|
Professional fees
|
|
|
0.7
|
|
|
$
|
0.62
|
|
|
|
0.4
|
|
|
$
|
0.34
|
|
|
|
0.3
|
|
|
|
0.28
|
|
|
|
82.4
|
|
Other
|
|
|
1.2
|
|
|
$
|
1.13
|
|
|
|
1.1
|
|
|
$
|
0.99
|
|
|
|
0.1
|
|
|
|
0.14
|
|
|
|
14.1
|
|
Total
|
|
$
|
6.5
|
|
|
$
|
6.06
|
|
|
$
|
5.8
|
|
|
$
|
5.08
|
|
|
$
|
0.7
|
|
|
$
|
0.98
|
|
|
|
19.3
|
%
|
Depletion, depreciation and amortization.
Our depletion, depreciation and amortization expense (“DD&A”) decreased $0.5 million, or 2%, to $19.5 million for the three months ended June 30, 2017, compared to $20 million for the three months ended June 30, 2016. Our DD&A per Boe increased by $0.68, or 4%, to $18.09 per Boe for the three months ended June 30, 2017, compared to $17.41 per Boe for the three months ended June 30, 2016. The decrease in DD&A over the prior-year period was primarily due to lower production. The increase in DD&A per Boe over the prior-year period was primarily due to higher oil and gas property carrying costs relative to estimated proved developed reserves.
Interest expense, net.
Our interest expense, net, decreased $1.9 million, or 28%, to $4.9 million for the three months ended June 30, 2017, compared to $6.8 million for the three months ended June 30, 2016. This decrease was primarily due to the reduction in our interest expense on outstanding Senior Notes ($2.7 million), partially offset by an increase in the applicable margin rates under our revolving credit facility.
Write-off of debt issuance costs.
We did not record a write-off of debt issuance costs for the three months ended June 30, 2017. We recorded a $0.6 million write-off of unamortized debt issuance costs for the three months ended June 30, 2016, related to the third amendment to our revolving credit facility that reduced our borrowing base from $450 million to $325 million.
Other income.
We did not record other income for the three months ended June 30, 2017. For the three months ended June 30, 2016, we recorded other income of $1.4 million. This was due to a contractual settlement of $1.4 million.
Income taxes.
Our income tax benefit decreased $4.2 million to $4.5 million for the three months ended June 30, 2017, from $8.7 million for the three months ended June 30, 2016. The decrease in the income tax benefit was primarily due to the decrease in net loss before income taxes in the 2017 period. Our effective income tax rate for the three months ended June 30, 2017, was 33.6%, compared to 35.1% for the three months ended June 30, 2016. The effective tax rate decreased for the three months ended June 30, 2017, compared to the prior-year period due to the impact of state taxes.
17
Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016
Oil, NGLs and gas sales
. Oil, NGLs and gas sales increased $11.3 million, or 28%, for the six months ended June 30, 2017, to $51.3 million, compared to $40 million for the six months ended June 30, 2016. The increase in oil, NGLs and gas sales was due to an increase in average realized commodity prices ($14.9 million) partially offset by a decrease in production volumes ($3.6 million). Production volumes decreased as a result of reduced drilling and completion activity in 2016.
Net loss
. Net loss for the six months ended June 30, 2017, was $149.7 million, or $1.91 per diluted share, compared to $29.7 million, or $0.72 per diluted share, for the six months ended June 30, 2016. Net loss for the six months ended June 30, 2017, included a tax provision of $134.1 million, a gain on debt extinguishment of $5.1 million due to the Exchange Transactions, an unrealized gain on commodity derivatives of $5.6 million and a realized loss on commodity derivatives of $1 million. The increase in the net loss for the six months ended June 30, 2017, was primarily due to the increase in our income tax provision of $150.1 million resulting from our cumulative change in ownership following the Exchange Transactions, partially offset by an increase in revenues ($11.3 million), a decrease in operating expenses ($3.3 million), a decrease in interest expense ($2.7 million) and the gain on debt extinguishment ($5.1 million).
Oil, NGLs and gas production.
Production for the six months ended June 30, 2017, totaled 2,107 MBoe (11.6 MBoe/d), compared to production of 2,314 MBoe (12.7 MBoe/d) in the prior-year period, a 9% decrease. Production for the six months ended June 30, 2017, was 27% oil, 35% NGLs and 38% gas, compared to 29% oil, 33% NGLs and 38% gas in the six months ended June 30, 2016. Production volumes decreased during the six months ended June 30, 2017, as a result of reduced drilling and completion activity in 2016.
Commodity derivative activities.
Our commodity derivative activity resulted in a realized loss of $1 million and a realized gain of $4.9 million for the six months ended June 30, 2017 and 2016, respectively. Our average realized price, including the effect of commodity derivatives, was $23.90 per Boe for the six months ended June 30, 2017, compared to $19.43 per Boe for the six months ended June 30, 2016. Realized gains and losses on commodity derivatives are derived from the relative movement of commodity prices in relation to the fixed notional pricing of our derivatives contracts for the respective periods. The unrealized gain on commodity derivatives was $5.6 million for the six months ended June 30, 2017, compared to an unrealized loss of $9 million for the six months ended June 30, 2016. As commodity prices increase or decrease, the fair value of the open portion of those positions decreases or increases, respectively.
Lease operating.
Our LOE decreased $3.2 million, or 27%, for the six months ended June 30, 2017, to $8.4 million, or $3.99 per Boe, compared to $11.6 million, or $5.01 per Boe, for the six months ended June 30, 2016. The decrease in LOE per Boe for the six months ended June 30, 2017, was primarily due to increased efficiency in our water handling operations, a decrease in well repairs, workovers and maintenance and a decrease in compressor rental and repair, partially offset by a decrease in production volumes and an increase in pumpers and supervision costs. The following table summarizes LOE per Boe.
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
|
|
|
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
% Change (Boe)
|
|
Compressor rental and repair
|
|
$
|
3.4
|
|
|
$
|
1.63
|
|
|
$
|
4.1
|
|
|
$
|
1.78
|
|
|
$
|
(0.7
|
)
|
|
$
|
(0.15
|
)
|
|
|
(8.4
|
)%
|
Well repairs, workovers and maintenance
|
|
|
1.8
|
|
|
|
0.87
|
|
|
|
2.8
|
|
|
|
1.19
|
|
|
|
(1.0
|
)
|
|
|
(0.32
|
)
|
|
|
(26.9
|
)
|
Water handling and other
|
|
|
1.7
|
|
|
|
0.78
|
|
|
|
3.3
|
|
|
|
1.44
|
|
|
|
(1.6
|
)
|
|
|
(0.66
|
)
|
|
|
(45.8
|
)
|
Pumpers and supervision
|
|
|
1.5
|
|
|
|
0.71
|
|
|
|
1.4
|
|
|
|
0.60
|
|
|
|
0.1
|
|
|
|
0.11
|
|
|
|
18.3
|
|
Total
|
|
$
|
8.4
|
|
|
$
|
3.99
|
|
|
$
|
11.6
|
|
|
$
|
5.01
|
|
|
$
|
(3.2
|
)
|
|
$
|
(1.02
|
)
|
|
|
(20.4
|
)%
|
Production and ad valorem taxes.
Our production and ad valorem taxes increased $1.1 million, or 31%, for the six months ended June 30, 2017, to $4.6 million, compared to $3.5 million for the six months ended June 30, 2016. Production and ad valorem taxes were $2.19 per Boe and $1.52 per Boe and approximately 9% and 8.8% of oil, NGLs and gas sales for the six months ended June 30, 2017 and 2016, respectively. The increase in production and ad valorem taxes was primarily a function of the increase in oil, NGLs and gas sales between the two periods.
Exploration.
We recorded $3.2 million, or $1.50 per Boe, and $2.2 million, or $0.95 per Boe, of exploration expense for the six months ended June 30, 2017 and 2016, respectively. The majority of exploration expense is non-cash and relates to lease expirations. The increase in exploration expense was primarily due to an increase in lease expirations in the six months ended June 30, 2017.
18
General and administrative
. Our G&A
in
crea
sed $
0.6
million, or
5
%, to $
12.5
million, or $
5.92
per Boe, for the
six
months ended June 30, 2017, compared to $
11.9
million, or $5.1
4
per Boe, for the
six
months ended June 30, 2016. The
increase
s
in G&A and G&A per Boe w
ere
primarily due
to
an increase in salaries and benefits and professional fees, partially offset by a decrease in
share-based compensation and lower production volumes compared to
the prior year period
. For the
six
months ended June 30, 2017,
G&A included
$0.3 million in expe
nse
related to cash-settled performance awards. These awards are re-measured each interim reporting period based on the fair market value of our common stock. Significant changes in the fair market value of our common stock will impact G&A per Boe.
The fol
lowing table summarizes G&A in millions and G&A per Boe.
|
|
Six Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
|
|
|
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
% Change (Boe)
|
|
Salaries and benefits
|
|
$
|
6.8
|
|
|
$
|
3.21
|
|
|
$
|
5.7
|
|
|
$
|
2.47
|
|
|
$
|
1.1
|
|
|
$
|
0.74
|
|
|
|
30.0
|
%
|
Share-based compensation
|
|
|
2.2
|
|
|
$
|
1.04
|
|
|
|
2.9
|
|
|
$
|
1.26
|
|
|
|
(0.7
|
)
|
|
|
(0.22
|
)
|
|
|
(17.5
|
)
|
Professional fees
|
|
|
1.2
|
|
|
$
|
0.58
|
|
|
|
1.0
|
|
|
$
|
0.42
|
|
|
|
0.2
|
|
|
|
0.16
|
|
|
|
38.1
|
|
Other
|
|
|
2.3
|
|
|
$
|
1.09
|
|
|
|
2.3
|
|
|
$
|
0.99
|
|
|
|
-
|
|
|
|
0.10
|
|
|
|
10.1
|
|
Total
|
|
$
|
12.5
|
|
|
$
|
5.92
|
|
|
$
|
11.9
|
|
|
$
|
5.14
|
|
|
$
|
0.6
|
|
|
$
|
0.78
|
|
|
|
15.2
|
%
|
Depletion, depreciation and amortization.
Our DD&A decreased $2.7 million, or 7%, to $37.5 million for the six months ended June 30, 2017, compared to $40.2 million for the six months ended June 30, 2016. Our DD&A per Boe increased by $0.42, or 2%, to $17.80 per Boe for the six months ended June 30, 2017, compared to $17.38 per Boe for the six months ended June 30, 2016. The decrease in DD&A over the prior-year period was primarily due to lower production. The increase in DD&A per Boe over the prior-year period was primarily due to higher oil and gas property carrying costs relative to estimated proved developed reserves.
Interest expense, net.
Our interest expense, net, decreased $2.7 million, or 21%, to $10.4 million for the six months ended June 30, 2017, compared to $13.1 million for the six months ended June 30, 2016. This decrease was primarily due to the reduction in our interest expense on outstanding Senior Notes ($4.4 million), partially offset by an increase in the applicable margin rates under our revolving credit facility.
Gain on debt extinguishment.
For the six months ended June 30, 2017, we recognized a gain of $5.1 million on the Exchange Transactions for the difference between the fair market value of the shares issued, a Level 1 fair value measurement, and the net carrying value of the Senior Notes exchanged.
Write-off of debt issuance costs.
We did not record a write-off of debt issuance costs for the six months ended June 30, 2017. We recorded a $0.6 million write-off of unamortized debt issuance costs for the six months ended June 30, 2016, related to the third amendment to our revolving credit facility that reduced our borrowing base from $450 million to $325 million.
Other income.
For the six months ended June 30, 2017, we recorded other income of $3,000. For the six months ended June 30, 2016, we recorded other income of $1.5 million. This was primarily due to a contractual settlement of $1.4 million.
Income taxes.
Our income tax provision increased $150.1 million to $134.2 million for the six months ended June 30, 2017, compared to an income tax benefit of $15.9 million for the six months ended June 30, 2016.
The Exchange Transactions triggered a cumulative change in ownership of our common stock by more than 50% under Section 382 of the Internal Revenue Code as of March 22, 2017. This established an annual limitation on the use of our pre-change net operating losses (“NOLs”) in the future. Accordingly, we recognized a valuation allowance on our deferred tax assets of $139.1 million.
The increase in the income tax provision was primarily due to the recognition of the valuation allowance on our NOLs incurred prior to the ownership change.
Liquidity and Capital Resources
We generally will rely on cash generated from operations, to the extent available, borrowings under our revolving credit facility and, to the extent that credit and capital market conditions will allow, future public or private equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned capital expenditures and to make acquisitions depends upon commodity prices, our future operating performance, availability of borrowings under our revolving credit facility, and more broadly, on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot predict whether additional liquidity from equity or debt financings beyond our revolving credit facility will be available on acceptable terms, or at all, in the foreseeable future.
19
Our cash flow from operations is driven by commodity prices, produ
ction volumes and the effect of commodity derivatives.
Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties. If commodity prices decline from current levels, our operating cash flows will decrease
and our lenders may reduce our borrowing base, thus limiting the amounts available to fund future capital expenditures. If we are unable to replace our oil, NGLs and gas reserves through acquisition, development and exploration, we may also suffer a reduct
ion in operating cash flows and access to funds under our revolving credit facility.
We believe we currently have adequate liquidity from cash generated from operations and unused borrowing capacity under our revolving credit facility for current working capital needs and maintenance of our current development plan. However, we may determine to use various financing sources, including the issuance of common stock, preferred stock, debt, convertible securities and other securities for future development of reserves, acquisitions, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that such financing will be available on acceptable terms or at all. Using some of these financing sources may require approval from our stockholders or the lenders under our revolving credit facility.
In the first quarter of 2017, we completed the Exchange Transactions, which reduced our Senior Notes by $145.1 million and will result in $44.3 million in future interest savings. The Exchange Transactions will benefit our future operating cash flow through the reduction of interest expense.
Liquidity
We define liquidity as funds available under our revolving credit facility and cash and cash equivalents. At June 30, 2017, we had $287 million in outstanding borrowings under our revolving credit facility and liquidity of $37.9 million, compared to $273 million in outstanding borrowings under our revolving credit facility and liquidity of $51.4 million at December 31, 2016. The table below summarizes our liquidity position at June 30, 2017, and December 31, 2016 (dollars in thousands).
|
|
Liquidity at
June 30,
|
|
|
Liquidity at
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
Borrowing base
|
|
$
|
325,000
|
|
|
$
|
325,000
|
|
Cash and cash equivalents
|
|
178
|
|
|
|
21
|
|
Long-term debt – Credit Facility
|
|
|
(287,000
|
)
|
|
|
(273,000
|
)
|
Undrawn letters of credit
|
|
|
(325
|
)
|
|
|
(575
|
)
|
Liquidity
|
|
$
|
37,853
|
|
|
$
|
51,446
|
|
Working Capital
Our working capital is affected primarily by our capital spending program. We had a working capital deficit of $20.6 million and $13.9 million at June 30, 2017, and December 31, 2016, respectively. The change in working capital was due to the timing of settlement of current assets and liabilities and an increase in current liabilities due to our capital expenditures for the six months ended June 30, 2017. To the extent we operate with a working capital deficit, we expect such deficit to be offset by liquidity available under our revolving credit facility.
Cash Flows
The following table summarizes our sources and uses of funds for the periods noted (in thousands).
|
|
Six Months Ended
June 30,
|
|
|
|
2017
|
|
|
2016
|
|
Cash provided by operating activities
|
|
$
|
16,220
|
|
|
$
|
8,592
|
|
Cash used in investing activities
|
|
|
(28,525
|
)
|
|
|
(9,363
|
)
|
Cash provided by financing activities
|
|
|
12,462
|
|
|
|
1,064
|
|
Net increase in cash and cash equivalents
|
|
$
|
157
|
|
|
$
|
293
|
|
Operating Activities
Cash provided by operating activities increased by 89%, or $7.6 million, to $16.2 million during the six months ended June 30, 2017, compared to the prior-year period. The increase in our cash provided by operating activities was primarily due to an increase in
20
oil, NGLs and gas sales from higher commodity prices
and
the decrease in interest expense,
partially offset by a decrease in realized gains from our commodity derivative activity.
Investing Activities
Cash used in investing activities increased by $19.2 million for the six months ended June 30, 2017, to $28.5 million, compared to the prior-year period. Cash used in investing activities for the six months ended June 30, 2017, was primarily attributable to drilling and development ($35.9 million) and infrastructure projects and equipment ($2.8 million). Cash used in investing activities was partially offset by changes in working capital associated with investing activities ($9.3 million) and a sales tax refund ($0.9 million). During the six months ended June 30, 2017, we drilled eleven horizontal wells and completed seven horizontal wells. At June 30, 2017, we had ten horizontal Wolfcamp wells waiting on completion, and one well being drilled.
Financing Activities
Cash provided by financing activities was $12.5 million for the six months ended June 30, 2017, compared to $1.1 million of cash used in financing activities in the prior-year period. We had $287 million in outstanding borrowings under our revolving credit facility at June 30, 2017, compared to $275 million in outstanding borrowings as of June 30, 2016. During the six months ended June 30, 2017, net cash provided by financing activities included net borrowings under our revolving credit facility of $14 million and changes in working capital associated with financing activities of $1.3 million, which were partially offset by $2.8 million in equity issuance costs associated with the Exchange Transactions.
Revolving Credit Facility
At June 30, 2017, the borrowing base and aggregate lender commitments under our revolving credit facility were $325 million, with maximum commitments from the lenders of $1 billion and a maturity date of May 7, 2019. We had outstanding borrowings of $287 million and $273 million under our revolving credit facility at June 30, 2017, and December 31, 2016, respectively. The weighted average interest rate applicable to borrowings under our revolving credit facility for the three months ended June 30, 2017, was 4.3%.
The borrowing base is redetermined semi-annually based upon a number of factors, including commodity prices and reserve levels. We or the lenders can each request one additional borrowing base redetermination each calendar year.
Our semi-annual borrowing base redetermination was completed on May 3, 2017, and our borrowing base and aggregate lender commitments were reaffirmed at $325 million.
At June 30, 2017, we were in compliance with all of our covenants, and there were no existing defaults or events of default under our debt instruments. To date, we have experienced no disruptions in our ability to access our revolving credit facility. However, our lenders have substantial ability to reduce our borrowing base on the basis of subjective factors, including the loan collateral value that each lender, in its discretion and using the methodology, assumptions and discount rates as such lender customarily uses in evaluating oil and gas properties, assigns to our properties.
Senior Notes
At June 30, 2017, $85.2 million of Senior Notes were outstanding, compared to $230.3 million as of December 31, 2016. The Exchange Transactions reduced the outstanding principal balance of our Senior Notes by $145.1 million, and reduced future interest payments by $44.3 million over the remaining term of the Senior Notes.
See Note 4 to our consolidated financial statements in this report for additional information regarding the Senior Notes.
Contractual Obligations
Our contractual obligations include long-term debt, operating lease obligations, asset retirement obligations and employment agreements with our executive officers. At June 30, 2017, outstanding borrowings under our revolving credit facility were $287 million, compared to $273 million at December 31, 2016. The Exchange Transactions reduced the outstanding principal of our Senior Notes from $230.3 million at December 31, 2016, to $85.2 million at June 30, 2017.
In January 2017, we amended our office space lease to reduce the aggregate leased space by approximately 5,500 square feet and extended the term to September 30, 2021. This amendment reduced our contractual obligations by approximately $0.4 million during the next three years, while increasing our total contractual obligations by $0.9 million over the extended term of the lease.
Since December 31, 2016, there have been no other material changes to our contractual obligations.
21
Off-Balance Sheet Arrangements
From time to time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of June 30, 2017, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit and operating lease agreements. We do not believe that these arrangements have, or are reasonably likely to have, a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
General Trends and Outlook
Our financial results depend upon many factors, particularly the price of oil, NGLs and gas. Commodity prices are affected by changes in market demand, which is impacted by factors outside of our control, including domestic and foreign supply of oil, NGLs and gas, overall domestic and global economic conditions, commodity processing, gathering and transportation availability and the availability of refining capacity, price and availability of alternative fuels, price and quantity of foreign imports, domestic and foreign governmental regulations, political conditions in or affecting other oil and gas producing countries, weather and technological advances affecting oil, NGLs and gas consumption. As a result, we cannot accurately predict future oil, NGLs and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues.
If the current oil or natural gas prices
decline from current levels, they
could
have a material adverse effect on our business, financial condition
and
results of operations and quantities of oil, natural gas and NGLs
reserves that may be economically produced and liquidity that may be accessed through our borrowing base under our revolving credit facility and through capital markets.
While we face the challenge of financing exploration, development and future acquisitions, we believe that we have adequate liquidity for current, near-term working capital needs and execution of our current development plan from cash generated from operations and unused borrowing capacity under our revolving credit facility. In addition, we may determine to use various financing sources, including the issuance of common stock, preferred stock, debt, convertible securities and other securities for future development of reserves, acquisitions, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that such financing will be available on acceptable terms or at all. Using some of these financing sources may require approval from the lenders under our revolving credit facility.
In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success. Future finding and development costs are subject to changes in the industry, including the costs of acquiring, drilling and completing our projects. We focus our efforts on increasing oil and gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations will depend on our ability to manage our overall cost structure.
Like all oil and gas production companies, we face the challenge of natural production declines. Oil and gas production from a given well naturally decreases over time. Additionally, our wells have a rapid initial production decline. We attempt to overcome this natural decline by drilling to develop and identify additional reserves, farm-ins or other joint drilling ventures, and by acquisitions. However, during times of severe price declines, we may from time to time reduce current capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially reduce our production volumes and revenues.
We believe the long-term outlook for our business is favorable despite the continued uncertainty of oil, NGLs and gas prices. Our resource base, current liquidity, risk management, including commodity derivative strategy, and disciplined investment of capital provide us with an opportunity to exploit and develop our asset base and maximize efficiency in our key operating area.