Item 2. Management’s Discussion and Analysis of Financial Condition and Results 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, 2017, filed with the Securities and Exchange Commission (“SEC”) on March 9, 2018. 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 and our ability to comply with the covenants in 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;
|
|
•
|
issuance of our common stock in connection with potential refinancing transactions that may cause substantial dilution;
|
|
•
|
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;
|
15
|
•
|
disruptions to, capacity constraints in or oth
er 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;
|
|
•
|
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, 2017, filed with the SEC on March 9, 2018.
|
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 150,000 net acres as of June 30, 2018. 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, 2017, our estimated proved reserves were 181.5 million barrels of oil equivalent (“MMBoe”), made up of 28% oil, 32% NGLs and 40% gas. The proved developed reserves were 37% of our total proved reserves at December 31, 2017. Substantially all of our proved reserves are located in the Permian Basin in Crockett and Schleicher counties, Texas. At June 30, 2018, we owned working interests in 809 producing oil and gas wells.
Second Quarter 2018 Activity
During the three months ended June 30, 2018, we produced 1,056 MBoe, or 11.6 MBoe/d, and increased production 2% compared to the three months ended March 31, 2018. During the quarter, we completed three horizontal wells. At June 30, 2018, we had three horizontal Wolfcamp wells waiting on completion.
We currently have one horizontal rig running in Project Pangea.
2018 Capital Expenditures
For the three months ended June 30, 2018, our capital expenditures totaled $13.5 million, consisting of $11.2 million for drilling and completion activities, $2 million for infrastructure projects and equipment and $0.3 million for lease acquisitions. For the six months ended June 30, 2018, our capital expenditures totaled $27.2 million, consisting of $23.6 million for completion activities, $3.3 million for infrastructure projects and equipment and $0.3 million for lease acquisitions. Our 2018 capital budget is a range of $50 million to $70 million.
16
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 ga
s, 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 renewal
s on reasonable terms. Although the impact of changes in these collective factors in the current 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.
17
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, 2018 and 2017. 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,
|
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
18,106
|
|
|
$
|
12,508
|
|
|
$
|
34,450
|
|
|
$
|
26,202
|
|
NGLs
|
|
|
8,852
|
|
|
|
6,019
|
|
|
|
16,184
|
|
|
|
12,079
|
|
Gas
|
|
|
3,368
|
|
|
|
6,442
|
|
|
|
8,464
|
|
|
|
13,043
|
|
Total oil, NGLs and gas sales
|
|
|
30,326
|
|
|
|
24,969
|
|
|
|
59,098
|
|
|
|
51,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash payment on derivative settlements
|
|
|
(1,982
|
)
|
|
|
3
|
|
|
|
(3,513
|
)
|
|
|
(958
|
)
|
Total oil, NGLs and gas sales including derivative
impact
|
|
$
|
28,344
|
|
|
$
|
24,972
|
|
|
$
|
55,585
|
|
|
$
|
50,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
278
|
|
|
|
281
|
|
|
|
550
|
|
|
|
560
|
|
NGLs (MBbls)
|
|
|
377
|
|
|
|
383
|
|
|
|
729
|
|
|
|
735
|
|
Gas (MMcf)
|
|
|
2,404
|
|
|
|
2,499
|
|
|
|
4,780
|
|
|
|
4,875
|
|
Total (MBoe)
|
|
|
1,056
|
|
|
|
1,080
|
|
|
|
2,076
|
|
|
|
2,107
|
|
Total (MBoe/d)
|
|
|
11.6
|
|
|
|
11.9
|
|
|
|
11.5
|
|
|
|
11.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
65.09
|
|
|
$
|
44.50
|
|
|
$
|
62.59
|
|
|
$
|
46.83
|
|
NGLs (per Bbl)
|
|
|
23.49
|
|
|
|
15.72
|
|
|
|
22.21
|
|
|
|
16.43
|
|
Gas (per Mcf)
|
|
|
1.40
|
|
|
|
2.58
|
|
|
|
1.77
|
|
|
|
2.68
|
|
Total (per Boe)
|
|
|
28.73
|
|
|
|
23.11
|
|
|
|
28.47
|
|
|
|
24.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash payment on derivative settlements (per Boe)
|
|
|
(1.88
|
)
|
|
|
—
|
|
|
|
(1.69
|
)
|
|
|
(0.46
|
)
|
Total including derivative impact (per Boe)
|
|
$
|
26.85
|
|
|
$
|
23.11
|
|
|
$
|
26.78
|
|
|
$
|
23.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses (per Boe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
4.77
|
|
|
$
|
3.92
|
|
|
$
|
4.96
|
|
|
$
|
3.99
|
|
Production and ad valorem taxes
|
|
|
2.43
|
|
|
|
2.09
|
|
|
|
2.44
|
|
|
|
2.19
|
|
Exploration
|
|
|
—
|
|
|
|
1.95
|
|
|
|
—
|
|
|
|
1.50
|
|
General and administrative
|
|
|
5.77
|
|
|
|
6.06
|
|
|
|
6.10
|
|
|
|
5.92
|
|
Depletion, depreciation and amortization
|
|
|
15.96
|
|
|
|
18.09
|
|
|
|
15.67
|
|
|
|
17.80
|
|
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.
18
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, 2018 Compared to Three Months Ended June 30, 2017
Oil, NGLs and gas sales
. Oil, NGLs and gas sales increased $5.3 million, or 21%, for the three months ended June 30, 2018, to $30.3 million, compared to $25 million for the three months ended June 30, 2017. The increase in oil, NGLs and gas sales was due to an increase in average realized commodity prices ($5.9 million) partially offset by a decrease in production volumes ($0.6 million). Production volumes decreased as a result of a decrease in well completions quarter over quarter.
We expect oil, NGLs and gas sales to increase in 2018 compared to 2017 due to improved commodity prices and an increase in production due to increased drilling and completion activity.
Net loss
. Net loss for the three months ended June 30, 2018, was $ 9.1 million, or $0.10 per diluted share, compared to $8.9 million, or $0.10 per diluted share, for the three months ended June 30, 2017. Net loss for the three months ended June 30, 2018, included a commodity derivative loss of $4.9 million. The increase in the net loss for the three months ended June 30, 2018, was primarily due to the increase in our commodity derivative loss ($6.1 million), an increase in interest expense ($1.3 million) and a decrease in our income tax benefit ($2.3 million), partially offset by an increase in revenue ($5.3 million) and a decrease in operating expenses ($4.2 million).
Oil, NGLs and gas production.
Production for the three months ended June 30, 2018, totaled 1,056 MBoe (11.6 MBoe/d), compared to production of 1,080 MBoe (11.9 MBoe/d) in the prior-year period, a 2% decrease.
Production for the three months ended June 30, 2018, was 26% oil, 36% NGLs and 38% gas, compared to 26% oil, 35% NGLs and 39% gas in the 2017 period.
Production volumes decreased during the three months ended June 30, 2018, due to natural production decline.
Commodity derivative (loss) gain.
The following table sets forth the components of our commodity derivative (loss) gain for the three months ended June 30, 2018, and 2017 (dollars in thousands).
|
|
Three Months Ended
June 30,
|
|
|
|
2018
|
|
|
2017
|
|
Net cash (payment) receipt on derivative settlements
|
|
$
|
(1,982
|
)
|
|
$
|
3
|
|
Non-cash fair value (loss) gain on derivatives
|
|
|
(2,902
|
)
|
|
|
1,228
|
|
Commodity derivative (loss) gain
|
|
$
|
(4,884
|
)
|
|
$
|
1,231
|
|
Historically, we have not designated our derivative instruments as cash-flow hedges. Commodity derivative settlements are derived from the relative movement of commodity prices in relation to the fixed notional pricing in our derivative contracts for the respective years. As commodity prices increase or decrease, the fair value of the open portion of those positions decreases or increases, respectively. We record our open derivative instruments at fair value on our consolidated balance sheets as either derivative assets or liabilities. For commodity derivatives not designated as a cash-flow hedge, we record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “commodity derivative (loss) gain.”
19
In
April 2018
, we entered into basis swaps for the NYMEX Calendar Monthly Average Roll (the “CMA Roll
”
) covering 2,000 Bbls per day for May 2018 through December 2018 at $0.66/bbl.
Basis swaps for the CMA Roll are pricing adjustments to the trade month versus
the delivery month for contract pricing.
These derivative contracts were designated as cash-flow hedges. The changes in fair value of the derivative contracts designated as cash-flow hedges, to the extent the hedge is effective, will be recognized in othe
r comprehensive income until the hedged item is recognized in revenue.
Oil, NGLs and gas sales includes $62,000 related to this cash flow hedge for the three months ended June 30, 2018.
Lease operating.
Our lease operating expenses (“LOE”) increased $0.8 million, or 19%, for the three months ended June 30, 2018, to $5 million, or $4.77 per Boe, compared to $4.2 million, or $3.92 per Boe, for the three months ended June 30, 2017. The increase in LOE per Boe for the three months ended June 30, 2018, was primarily due to well repairs, workovers and maintenance and water handling. The increase in well repairs, workovers and maintenance was due to an increase in workover activity for the three months ended June 30, 2018. The following table summarizes LOE per Boe.
|
|
Three Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
2017
|
|
|
Change
|
|
|
|
|
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
% Change (Boe)
|
|
Compressor rental and repair
|
|
$
|
1.6
|
|
|
$
|
1.56
|
|
|
$
|
1.7
|
|
|
$
|
1.59
|
|
|
$
|
(0.1
|
)
|
|
$
|
(0.03
|
)
|
|
|
(1.9
|
)%
|
Well repairs, workovers and maintenance
|
|
|
1.4
|
|
|
|
1.33
|
|
|
|
0.9
|
|
|
|
0.85
|
|
|
|
0.5
|
|
|
|
0.48
|
|
|
|
56.5
|
|
Water handling and other
|
|
|
1.2
|
|
|
|
1.16
|
|
|
|
0.8
|
|
|
|
0.76
|
|
|
|
0.4
|
|
|
|
0.40
|
|
|
|
52.6
|
|
Pumpers and supervision
|
|
|
0.8
|
|
|
|
0.72
|
|
|
|
0.8
|
|
|
|
0.72
|
|
|
|
—
|
|
|
|
—
|
|
|
|
0.0
|
|
Total
|
|
$
|
5.0
|
|
|
$
|
4.77
|
|
|
$
|
4.2
|
|
|
$
|
3.92
|
|
|
$
|
0.8
|
|
|
$
|
0.85
|
|
|
|
21.7
|
%
|
Production and ad valorem taxes.
Our production and ad valorem taxes increased $0.3 million, or 14%, for the three months ended June 30, 2018, to $2.6 million compared to $2.3 million for the three months ended June 30, 2017. Production and ad valorem taxes were $2.43 per Boe and $2.09 per Boe and approximately 8.5% and 9% of oil, NGLs and gas sales for the three months ended June 30, 2018 and 2017, respectively. The increase in production and ad valorem taxes was primarily a function of the increase in oil, NGLs and gas sales between the current and prior periods.
Exploration.
We recorded exploration expense of $3,000 for the three months ended June 30, 2018, compared to $2.1 million, or $1.95 per Boe for the three months ended June 30, 2017. The decrease in exploration expense was primarily due to no lease expirations in the second quarter of 2018.
General and administrative
. Our general and administrative expenses (“G&A”) decreased $0.4 million, or 7%, to $6.1 million, or $5.77 per Boe, for the three months ended June 30, 2018, compared to $6.5 million, or $6.06 per Boe, for the three months ended June 30, 2017. The decrease in G&A and G&A per Boe was primarily due to a decrease in share-based compensation and professional fees. For the three months ended June 30, 2018,
G&A included an expense of $0.5 million compared to an expense of $0.4 million for the three months ended June 30, 2017, 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 and G&A per Boe.
The following table summarizes G&A in millions and G&A per Boe.
|
|
Three Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
2017
|
|
|
Change
|
|
|
|
|
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
% Change (Boe)
|
|
Salaries and benefits
|
|
$
|
3.6
|
|
|
$
|
3.40
|
|
|
$
|
3.6
|
|
|
$
|
3.36
|
|
|
$
|
-
|
|
|
$
|
0.04
|
|
|
|
1.2
|
%
|
Share-based compensation
|
|
|
0.7
|
|
|
$
|
0.62
|
|
|
|
1.0
|
|
|
$
|
0.95
|
|
|
|
(0.3
|
)
|
|
|
(0.33
|
)
|
|
|
(34.7
|
)
|
Professional fees
|
|
|
0.5
|
|
|
$
|
0.48
|
|
|
|
0.7
|
|
|
$
|
0.62
|
|
|
|
(0.2
|
)
|
|
|
(0.14
|
)
|
|
|
(22.6
|
)
|
Other
|
|
|
1.3
|
|
|
$
|
1.27
|
|
|
|
1.2
|
|
|
$
|
1.13
|
|
|
|
0.1
|
|
|
|
0.14
|
|
|
|
12.4
|
|
Total
|
|
$
|
6.1
|
|
|
$
|
5.77
|
|
|
$
|
6.5
|
|
|
$
|
6.06
|
|
|
$
|
(0.4
|
)
|
|
$
|
(0.29
|
)
|
|
|
(4.8
|
)%
|
Depletion, depreciation and amortization.
Our depletion, depreciation and amortization expense (“DD&A”) decreased $2.7 million, or 14%, to $16.8 million for the three months ended June 30, 2018, compared to $19.5 million for the three months ended June 30, 2017. Our DD&A per Boe decreased by $2.13, or 12%, to $15.96 per Boe for the three months ended June 30, 2018, compared to $18.09 per Boe for the three months ended June 30, 2017.
The decrease in DD&A and DD&A per Boe over the prior-year period was primarily due to an increase in estimated proved developed reserves.
Interest expense, net. Our interest expense, net, increased $1.3 million, or 26%, to $6.2 million for the three months ended June 30, 2018, compared to $4.9 million for the three months ended June 30, 2017. This increase was primarily due to increases in the
20
applicable margin rates, outstanding borrowings and floating interest rates under our revolving credit facility.
The weighted average inter
est rate applicable to borrowings under the revolving credit facility for the three months ended June 30, 2018, was 5.8% compared to 4.3% for the three months ended June 30, 2017.
Income taxes.
For the three months ended June 30, 2018, our income tax benefit was $2.2 million, compared to an income tax benefit of $4.5 million for the three months ended June 30, 2017.
The following table reconciles our income tax expense for the three months ended June 30, 2018, and 2017, to the U.S. federal statutory rates of 21% and 35%, respectively (dollars in thousands).
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2018
|
|
|
2017
|
|
Statutory tax at 21% and 35%, respectively
|
|
$
|
(2,372
|
)
|
|
$
|
(4,691
|
)
|
State taxes, net of federal impact
|
|
|
112
|
|
|
|
154
|
|
Share-based compensation tax shortfall
|
|
|
—
|
|
|
|
22
|
|
Nondeductible compensation
|
|
|
36
|
|
|
|
—
|
|
Other differences
|
|
|
2
|
|
|
|
6
|
|
Write-off of deferred tax assets
|
|
|
—
|
|
|
|
—
|
|
Income tax (benefit) provision
|
|
$
|
(2,222
|
)
|
|
$
|
(4,509
|
)
|
On December 22, 2017, the Tax Cuts and Jobs Act was enacted which, among other things, lowered the U.S. federal income tax rate applicable to corporations from 35% to 21% and repealed the corporate alternative minimum tax. We expect our effective tax rate to be lower compared to the prior year due to the change in tax legislation.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017
Oil, NGLs and gas sales
. Oil, NGLs and gas sales increased $7.8 million, or 15%, for the six months ended June 30, 2018, to $59.1 million, compared to $51.3 million for the six months ended June 30, 2017. The increase in oil, NGLs and gas sales was due to an increase in average realized commodity prices ($8.5 million) partially offset by a decrease in production volumes ($0.7 million). Production volumes decreased as a result of no well completions in the fourth quarter of 2017.
We expect oil, NGLs and gas sales to increase in 2018 compared to 2017 due to improved commodity prices and an increase in production due to increased well completion activity.
Net loss
. Net loss for the six months ended June 30, 2018, was $16.5 million, or $0.17 per diluted share, compared to $149.7 million, or $1.91 per diluted share, for the six months ended June 30, 2017. Net loss for the six months ended June 30, 2018, included a commodity derivative loss of $6.8 million. The decrease in the net loss for the six months ended June 30, 2018, was primarily due to the debt-for-equity exchange transactions completed in the six months ended June 30, 2017. In connection with the exchange transactions, we recognized a gain on debt extinguishment of $5.1 million and a write-off of deferred tax assets of $139.1 million resulting from our cumulative change in ownership.
Oil, NGLs and gas production.
Production for the six months ended June 30, 2018, totaled 2,076 MBoe (11.5 MBoe/d), compared to production of 2,107 MBoe (11.6 MBoe/d) in the prior-year period, a 1% decrease.
Production for the six months ended June 30, 2018, and June 30, 2017, was 27% oil, 35% NGLs and 38% gas.
Production volumes decreased during the six months ended June 30, 2018, due to natural production decline.
Commodity derivative (loss) gain.
The following table sets forth the components of our commodity derivative (loss) gain for the six months ended June 30, 2018, and 2017 (dollars in thousands).
|
|
Six Months Ended
June 30,
|
|
|
|
2018
|
|
|
2017
|
|
Net cash payment on derivative settlements
|
|
$
|
(3,513
|
)
|
|
$
|
(958
|
)
|
Non-cash fair value (loss) gain on derivatives
|
|
|
(3,299
|
)
|
|
|
5,633
|
|
Commodity derivative (loss) gain
|
|
$
|
(6,812
|
)
|
|
$
|
4,675
|
|
21
Lease operating.
Our LOE increased $
1.9
million, or
23
%, for the
six
months ended June 30, 2018, to $
10.3
million, or $
4.96
per Boe, compared to $
8.4
million, or $3.
99
per Boe, for the
six
months ended June 30, 2017. The increase in LOE per Boe for the
six
months ended June 30, 2018, was primarily due to well repairs, workovers and maintenance
and water handling
.
The increase in well repairs, workover
s and maintenance was due to an increase in workover activity for the six months ended June 30, 2018.
The following table summarizes LOE per Boe.
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
2017
|
|
|
Change
|
|
|
|
|
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
% Change (Boe)
|
|
Compressor rental and repair
|
|
$
|
3.4
|
|
|
$
|
1.65
|
|
|
$
|
3.4
|
|
|
$
|
1.63
|
|
|
$
|
-
|
|
|
$
|
0.02
|
|
|
|
1.2
|
%
|
Well repairs, workovers and maintenance
|
|
|
3.0
|
|
|
|
1.44
|
|
|
|
1.8
|
|
|
|
0.87
|
|
|
|
1.2
|
|
|
|
0.57
|
|
|
|
65.5
|
|
Water handling and other
|
|
|
2.3
|
|
|
|
1.12
|
|
|
|
1.7
|
|
|
|
0.78
|
|
|
|
0.6
|
|
|
|
0.34
|
|
|
|
43.6
|
|
Pumpers and supervision
|
|
|
1.6
|
|
|
|
0.75
|
|
|
|
1.5
|
|
|
|
0.71
|
|
|
|
0.1
|
|
|
|
0.04
|
|
|
|
5.6
|
|
Total
|
|
$
|
10.3
|
|
|
$
|
4.96
|
|
|
$
|
8.4
|
|
|
$
|
3.99
|
|
|
$
|
1.9
|
|
|
$
|
0.97
|
|
|
|
24.3
|
%
|
Production and ad valorem taxes.
Our production and ad valorem taxes increased $0.5 million, or 10%, for the six months ended June 30, 2018, to $5.1 million compared to $4.6 million for the six months ended June 30, 2017. Production and ad valorem taxes were $2.44 per Boe and $2.19 per Boe and approximately 8.6% and 9% of oil, NGLs and gas sales for the six months ended June 30, 2018 and 2017, 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 exploration expense of $3,000 for the six months ended June 30, 2018, compared to $3.2 million, or $1.50 per Boe for the six months ended June 30, 2017. The decrease in exploration expense was primarily due to no lease expirations in the six months ended June 30, 2018.
General and administrative
. Our G&A increased $0.2 million, or 1%, to $12.7 million, or $6.10 per Boe, for the six months ended June 30, 2018, compared to $12.5 million, or $5.92 per Boe, for the six months ended June 30, 2017. The increase in G&A and G&A per Boe was primarily due an increase expense related to cash-settled performance awards. For the six months ended June 30, 2018,
G&A included an expense of $0.8 million compared to an expense of $0.3 million for the six months ended June 30, 2017, 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 and G&A per Boe.
The following table summarizes G&A in millions and G&A per Boe.
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
2017
|
|
|
Change
|
|
|
|
|
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
$MM
|
|
|
Boe
|
|
|
% Change (Boe)
|
|
Salaries and benefits
|
|
$
|
7.4
|
|
|
$
|
3.56
|
|
|
$
|
6.8
|
|
|
$
|
3.21
|
|
|
$
|
0.6
|
|
|
$
|
0.35
|
|
|
|
10.9
|
%
|
Share-based compensation
|
|
|
1.5
|
|
|
$
|
0.71
|
|
|
|
2.2
|
|
|
$
|
1.04
|
|
|
|
(0.7
|
)
|
|
|
(0.33
|
)
|
|
|
(31.7
|
)
|
Professional fees
|
|
|
1.2
|
|
|
$
|
0.59
|
|
|
|
1.2
|
|
|
$
|
0.58
|
|
|
|
-
|
|
|
|
0.01
|
|
|
|
1.7
|
|
Other
|
|
|
2.6
|
|
|
$
|
1.24
|
|
|
|
2.3
|
|
|
$
|
1.09
|
|
|
|
0.3
|
|
|
|
0.15
|
|
|
|
13.8
|
|
Total
|
|
$
|
12.7
|
|
|
$
|
6.10
|
|
|
$
|
12.5
|
|
|
$
|
5.92
|
|
|
$
|
0.2
|
|
|
$
|
0.18
|
|
|
|
3.0
|
%
|
Depletion, depreciation and amortization.
Our DD&A decreased $5 million, or 13%, to $32.5 million for the six months ended June 30, 2018, compared to $37.5 million for the six months ended June 30, 2017. Our DD&A per Boe decreased by $2.13, or 12%, to $15.67 per Boe for the six months ended June 30, 2018, compared to $17.80 per Boe for the six months ended June 30, 2017.
The decrease in DD&A and DD&A per Boe over the prior-year period was primarily due to an increase in estimated proved developed reserves.
Interest expense, net. Our interest expense, net, increased $1.7 million, or 16%, to $12.1 million for the six months ended June 30, 2018, compared to $10.4 million for the six months ended June 30, 2017. This increase was primarily due to an increase in the applicable margin rates, outstanding borrowings and floating interest rates under our revolving credit facility. The weighted average interest rate applicable to borrowings under the revolving credit facility for the six months ended June 30, 2018, was 5.6% compared to 4.2% for the six months ended June 30, 2017.
Gain on debt extinguishment.
In the six months ended June 30, 2018, we did not repurchase or retire any outstanding debt. In the six months ended June 30, 2017, we completed two debt-for-equity exchange transactions, which reduced the principal amount of
22
our outstanding 7% Senior Notes due 2021 (“Senior Notes”) by $145.1 million. We recognized a gain of $5.1 million on the exchange tra
nsactions 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.
Income taxes.
For the six months ended June 30, 2018, our income tax benefit was $3.8 million, compared to an income tax expense of $134.2 million for the six months ended June 30, 2017.
The following table reconciles our income tax expense for the six months ended June 30, 2018, and 2017, to the U.S. federal statutory rates of 21% and 35%, respectively (dollars in thousands).
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2018
|
|
|
2017
|
|
Statutory tax at 21% and 35%, respectively
|
|
$
|
(4,274
|
)
|
|
$
|
(5,415
|
)
|
State taxes, net of federal impact
|
|
|
274
|
|
|
|
195
|
|
Share-based compensation tax shortfall
|
|
|
70
|
|
|
|
312
|
|
Nondeductible compensation
|
|
|
93
|
|
|
|
—
|
|
Other differences
|
|
|
5
|
|
|
|
9
|
|
Write-off of deferred tax assets
|
|
|
—
|
|
|
|
139,090
|
|
Income tax (benefit) provision
|
|
$
|
(3,832
|
)
|
|
$
|
134,191
|
|
On December 22, 2017, the Tax Cuts and Jobs Act was enacted which, among other things, lowered the U.S. Federal income tax rate applicable to corporations from 35% to 21% and repealed the corporate alternative minimum tax. We expect our effective tax rate to be lower compared to the prior year due to the change in tax legislation.
In the six months ended June 30, 2017, i
n connection with the debt-for-equity exchange transactions, we recorded a write-off of deferred tax assets of $139.1 million resulting from our cumulative change in ownership.
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 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.
Our cash flow from operations is driven by commodity prices, production 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 reduction in operating cash flows and access to funds under our revolving credit facility.
At June 30, 2018, we were in compliance with all required covenants under our revolving credit facility. If commodity prices decline from current levels or we fail to reduce our total debt, we may trigger non-compliance with required financial covenants in the future and otherwise adversely impact our ability to operate.
We believe we 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, including debt reduction, 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.
23
Liquidity
We define liquidity as funds available under our revolving credit facility and cash and cash equivalents.
Our liquidity is subject to our continued compliance with the financial covenants under our revolving credit facility. At June 30, 2018, we were in compliance with all of our covenants, and there were no existing defaults or events of default under our debt instruments.
Our revolving credit facility includes, among other financial covenants, a leverage covenant, which requires us to reduce our leverage as of the end of the first quarter of 2019. Our leverage is currently above the level required by the leverage covenant, and factors beyond our control may affect our ability to comply with the leverage covenant by the first quarter of 2019. Failure to comply with the leverage covenant may result in an event of default.
See Note 5 to our consolidated financial statements in this report for additional information regarding the leverage covenant and the other financial covenants under our revolving credit facility.
At June 30, 2018, we had $297.5 million in outstanding borrowings under our revolving credit facility and liquidity of $27.2 million, compared to $291 million in outstanding borrowings under our revolving credit facility and liquidity of $33.7 million at December 31, 2017. The table below summarizes our liquidity position at June 30, 2018, and December 31, 2017 (dollars in thousands).
|
|
Liquidity at
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
Borrowing base
|
|
$
|
325,000
|
|
|
$
|
325,000
|
|
Cash and cash equivalents
|
|
22
|
|
|
|
21
|
|
Long-term debt – Credit Facility
|
|
|
(297,500
|
)
|
|
|
(291,000
|
)
|
Undrawn letters of credit
|
|
|
(325
|
)
|
|
|
(325
|
)
|
Liquidity
|
|
$
|
27,197
|
|
|
$
|
33,696
|
|
Working Capital
Our working capital is affected primarily by our capital spending program. We had a working capital deficit of $16 million and $8.4 million at June 30, 2018, and December 31, 2017, respectively. The change in working capital was primarily due to the termination of a prepaid hydraulic fracturing services agreement, which increased our working capital deficit by $4.3 million. Additionally, our working capital deficit increased due to a decrease in the fair value of our outstanding commodity derivative positions ($3.5 million). 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,
|
|
|
|
2018
|
|
|
2017
|
|
Cash provided by operating activities
|
|
$
|
14,250
|
|
|
$
|
16,220
|
|
Cash used in investing activities
|
|
|
(19,463
|
)
|
|
|
(28,525
|
)
|
Cash provided by financing activities
|
|
|
5,214
|
|
|
|
12,462
|
|
Net increase in cash and cash equivalents
|
|
$
|
1
|
|
|
$
|
157
|
|
Operating Activities
Cash provided by operating activities decreased by 12%, or $1.9 million, to $14.3 million during the six months ended June 30, 2018, compared to the prior-year period. The decrease in our cash provided by operating activities was due to an increase in LOE ($1.9 million), interest expense ($1.7 million), net cash settlements under our commodity derivatives ($2.6 million) and changes in working capital related to operating activities ($2.4 million), partially offset by an increase in oil, NGLs and gas sales ($7.8 million) from higher commodity prices. We expect our operating cash flow to increase from prior year periods due to anticipated higher commodity prices.
Investing Activities
Cash used in investing activities decreased by $9.1 million for the six months ended June 30, 2018, to $19.5 million, compared to the prior-year period. Cash used in investing activities for the six months ended June 30, 2018, was primarily attributable to drilling
24
and development ($
23.6
million)
,
infrastructure projects and
equipment ($
3.3
million)
and lease acquisitions
($0.3 million)
. Cash used in investing activities was partially offset by changes in working capital associated with investing activities ($
7.7
million). The change in working capital associated with investi
ng activities was primarily due to the termination of a prepaid hydraulic fracturing services agreement. During the
six
months ended
June 30
, 2018, we completed
seven
horizontal wells. At
June 30
, 2018, we had
three
horizontal Wolfcamp wells waiting on com
pletion.
Financing Activities
Cash provided by financing activities was $5.2 million for the six months ended June 30, 2018, compared to $12.5 million of cash provided by financing activities in the prior-year period.
We had $297.5 million in outstanding borrowings under our revolving credit facility at June 30, 2018, compared to $291 million in outstanding borrowings as of December 31, 2017. During the six months ended June 30, 2018, net cash provided by financing activities included net borrowings under our revolving credit facility of $6.5 million, tax withholdings related to restricted stock of $0.6 million and changes in working capital associated with financing activities of $0.6 million.
As market conditions warrant and subject to our contractual restrictions in our revolving credit facility or otherwise, liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure. We may accomplish this through open market or privately negotiated transactions, which may include, among other things, repurchases of our common stock or outstanding debt, debt for debt or debt for equity exchanges or refinancings, and private or public equity raises and rights offerings. Many of these alternatives may require the consent of current lenders, stockholders or bond holders, and there is no assurance that we will be able to execute any of these alternatives on acceptable terms or at all. The amounts involved in any such transaction, individually or in the aggregate, may be material.
Revolving Credit Facility
At June 30, 2018, 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, 2020. We had outstanding borrowings of $297.5 million and $291 million under our revolving credit facility at June 30, 2018, and December 31, 2017, respectively. The weighted average interest rate applicable to borrowings under our revolving credit facility for the three months ended June 30, 2018, was 5.8%.
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 1, 2018, and our borrowing base and aggregate lender commitments were reaffirmed at $325 million.
At June 30, 2018, we were in compliance with all of our covenants, and there were no existing defaults or events of default under our debt instruments. See Note 5 to our consolidated financial statements in this report for additional information regarding our revolving credit facility and our principal financial covenants. 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, 2018, and December 31, 2017, $85.2 million of our 7% Senior Notes were outstanding.
See Note 5 to our consolidated financial statements in this report for additional information regarding the Senior Notes.
Wilks, a related party, purchased a portion of our outstanding Senior Notes in the open market in 2017 and 2018. The Company believes
that Wilks held approximately $60 million of our outstanding Senior Notes as of June 30, 2018. The Senior Notes held by Wilks are included in Senior Notes, net on our consolidated balance sheets. Our interest expense includes interest attributable to any Senior Notes held by Wilks on our consolidated statements of operations. On April 12, 2018, Wilks disclosed on Schedule 13D/A that they intend to engage in discussions with the Company regarding their investment in the Company, including the possible acquisition of additional shares of common stock through the exchange of additional 7% Senior Secured Notes due 2021 currently held by Wilks.
We have engaged, and intend to continue to engage, in discussions with potential counterparties, including the Wilks, regarding a broad range of transactions to reduce our leverage as we continue to explore these alternatives. Certain of these alternatives may require the consent of current lenders, stockholders or bond holders. There is no assurance that we will be able to execute any of these alternatives on acceptable terms, or at all.
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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, 2018, outstanding borrowings under our revolving credit facility were $297.5 million, compared to $291 million at December 31, 2017.
Since December 31, 2017, there have been no other material changes to our contractual obligations.
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, 2018, 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. As commodity prices improve, service costs in our industry may also increase. 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 outlook for our business is favorable despite the continued uncertainty of oil, NGLs and gas prices. Our resource base, adequate current liquidity, risk management, including commodity derivative strategy, and disciplined investment of capital provide us with an opportunity to exploit and develop our positions and maximize efficiency in our key operating area.