Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in our Annual Report on Form 10-K for the year ended
December 31, 2018
filed with the SEC on March 15, 2019, and the historical unaudited condensed consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report.
Except as otherwise noted, all tabular amounts are in thousands, except per unit values.
Critical Accounting Policies
There have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K for the year ended
December 31, 2018
, except for the adoption of the leasing standard which was effective January 1, 2019.
General
We are an independent energy company primarily engaged in the acquisition, development and production of oil and gas in the United States. Historically, we have grown through the acquisition and subsequent development of producing properties, principally through the development of shale or tight oil reservoirs in areas known to be productive of oil and gas utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling and stage fracturing. As a result of these activities, we believe that we have a number of development opportunities on our properties. In addition, we intend to expand upon our development activities with complementary acreage acquisitions in our core areas of operation. Success in our development activities is critical in the maintenance and growth of our current production levels and associated reserves.
Factors Affecting Our Financial Results
Our financial results depend upon many factors which significantly affect our results of operations including the following:
|
•
|
commodity prices and the effectiveness of our hedging arrangements;
|
|
•
|
the level of total sales volumes of oil and gas;
|
|
•
|
the availability of and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;
|
|
•
|
the level of and interest rates on borrowings; and
|
|
•
|
the level and success of exploration and development activity.
|
Commodity Prices and Hedging Arrangements
.
The results of our operations are highly dependent upon the prices received for our oil and gas production. The prices we receive for our production are dependent upon spot market prices, differentials and the effectiveness of our derivative contracts, which we sometimes refer to as hedging arrangements. Substantially all of our sales of oil and gas are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and gas production are dependent upon numerous factors beyond our control. Significant declines in prices for oil and gas could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis.
Oil and gas prices have been volatile and are expected to continue to be volatile. As a result of the many uncertainties associated with the world political environment, worldwide supplies of oil, NGL and gas, the availability of other worldwide energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, we are unable to predict what changes may occur in oil, NGL and gas prices in the future. The market price of oil and condensate, NGL and gas in
2019
will impact the amount of cash generated from operating activities, which will in turn impact our financial position.
During the
six months ended June 30, 2019
, the NYMEX future price for oil averaged
$57.20
per Bbl as compared to $65.47 per Bbl in the same period of
2018
. During the
six months ended June 30, 2019
, the NYMEX future spot price for gas averaged
$2.69
per MMBtu compared to $2.84 per MMBtu in the same period of
2018
. Prices closed on
June 30, 2019
at
$58.47
per Bbl of oil and
$2.31
per MMBtu of gas, compared to closing on
June 30, 2018
at $74.15 per Bbl of oil and $2.92 per MMBtu of gas. On August 6, 2019, prices closed at
$53.63
per Bbl of oil and
$2.11
per MMBtu of gas. If commodity prices decline, our revenue and cash flow from operations will also likely decline. In addition, lower commodity prices could also reduce the amount of oil and gas that we can produce economically. If oil and gas prices decline, our revenues, profitability and cash flow from operations will also likely decrease which could cause us to alter our business plans, including reducing our drilling activities. Such declines have required, and in future periods could also require us to write down the carrying value of our oil and gas assets which would also cause a reduction in net income. The prices that we receive are also impacted by basis differentials, which can be significant, and are dependent on actual delivery points. Finally, low commodity prices will likely cause a reduction of our proved reserves, resulting in a reduction of the borrowing base under our credit facility.
The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to:
|
•
|
basis differentials which are dependent on actual delivery location;
|
|
•
|
adjustments for BTU content;
|
|
•
|
quality of the hydrocarbons; and
|
|
•
|
gathering, processing and transportation costs.
|
The following table sets forth our average differentials for the
six months ended June 30, 2019
and
2018
:
|
|
Oil - NYMEX
|
|
|
Gas - NYMEX
|
|
|
|
2019
|
|
|
2018
|
|
|
2019
|
|
|
2018
|
|
Average realized price (1)
|
|
$
|
52.04
|
|
|
$
|
60.84
|
|
|
$
|
0.92
|
|
|
$
|
1.73
|
|
Average NYMEX price
|
|
|
57.20
|
|
|
|
65.47
|
|
|
|
2.69
|
|
|
|
2.84
|
|
Differential
|
|
$
|
(5.16
|
)
|
|
$
|
(4.63
|
)
|
|
$
|
(1.77
|
)
|
|
$
|
(1.11
|
)
|
(1) Excludes the impact of derivative activities.
At
June 30, 2019
, our derivative contracts consisted of NYMEX-based fixed price swaps and NYMEX basis swaps. Under fixed price swaps, we receive a fixed price for our production and pay a variable market price to the contract counter-party. Under basis swaps, we receive payment if the basis differential is greater than our swap price and pay when the differential is less than our swap price.
Our derivative contracts equate to approximately
85%
of the estimated oil production from our net proved developed producing reserves (based on reserve estimates at
December 31, 2018
) from July 1, 2019 through December 31, 2019,
85%
in 2020 and
75%
in 2021. By removing a portion of price volatility on our future oil and gas production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations for those periods. However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow. We have in the past and will in the future sustain losses on our derivative contracts if market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain gains on our commodity derivative contracts. For the
six months ended June 30, 2019
, we realized a loss of
$23.4
million, consisting of a loss of
$2.8
million on closed contracts and a loss of
$20.6
million related to open contracts. For the
six months ended June 30, 2018
, we realized a loss of
$27.6
million consisting of a loss of
$9.8
million on closed contracts and a loss of
$17.8
million related to open contracts. We have not designated any of these derivative contracts as hedges as prescribed by applicable accounting rules.
The following table sets forth our derivative contracts at
June 30, 2019
:
|
|
Oil - WTI
|
|
Contract Periods
|
|
Daily Volume (Bbl)
|
|
|
Swap Price (per Bbl)
|
|
Fixed Swaps
|
|
|
|
|
|
|
|
|
2019 July - December
|
|
|
4,097
|
|
|
$
|
56.85
|
|
2020 January - December
|
|
|
3,023
|
|
|
$
|
55.25
|
|
2021 January - December
|
|
|
2,051
|
|
|
$
|
59.78
|
|
|
|
|
|
|
|
|
|
|
Basis Swaps
|
|
|
|
|
|
|
|
|
2019 July - December
|
|
|
4,000
|
|
|
$
|
2.98
|
|
2020 January - December
|
|
|
4,000
|
|
|
$
|
2.98
|
|
At
June 30, 2019
, the aggregate fair market value of our commodity derivative contracts was a net liability of approximately
$6.4
million.
Production Volumes.
Our proved reserves will decline as oil and gas is produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities. Based on the reserve information set forth in our reserve report as of
December 31, 2018
, our average annual estimated decline rate for our net proved developed producing reserves is 35%; 19%; 14%; 11% and 9% in 2019, 2020, 2021, 2022 and 2023, respectively, 11% in the following five years, and approximately 8% thereafter. These rates of decline are estimates and actual production declines could be materially different. While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and property sales. Our ability to acquire or find additional reserves in the future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects.
We had capital expenditures during the
six months ended June 30, 2019
of $63.9 million related to our exploration and development activities. We have a capital expenditure budget for
2019
of approximately $86.0 million, of which approximately $47.0 million is allocated to acquiring additional acreage and developing our Bone Spring/Wolfcamp acres in the Permian/Delaware Basin. The
2019
budget also allocates approximately $27.0 million for developing our Williston Basin/Bakken/Three Forks play in North Dakota, with the remaining amount allocated to acquisitions, facilities and general corporate purposes. The
2019
capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources, our financial results and our ability to obtain permits for drilling locations. Our capital expenditures could also include expenditures for the acquisition of producing properties, if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows from operations will decrease which may result in a reduction of the capital expenditure budget. If we decrease our capital expenditure budget, we may not be able to offset oil and gas production decreases caused by natural field declines.
The following table presents historical net production volumes for the
three and six months ended June 30, 2019
and
2018
:
|
|
Three Months Ended June 30,
|
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
|
2018
|
|
|
2019
|
|
|
2018
|
|
Total production (MBoe)
|
|
|
871
|
|
|
|
745
|
|
|
|
1,850
|
|
|
|
1,689
|
|
Average daily production (Boepd)
|
|
|
9,572
|
|
|
|
8,188
|
|
|
|
10,219
|
|
|
|
9,330
|
|
% Oil
|
|
|
71
|
%
|
|
|
59
|
%
|
|
|
69
|
%
|
|
|
62
|
%
|
The following table presents our net oil, gas and NGL production, the average sales price per Bbl of oil and NGL and per Mcf of gas produced and the average cost of production per Boe of production sold, for the
three and six months ended June 30, 2019
and
2018
, by our major operating regions:
|
|
Three Months Ended June 30,
|
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
|
2018
|
|
|
2019
|
|
|
2018
|
|
Oil production (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountain
|
|
|
321
|
|
|
|
247
|
|
|
|
766
|
|
|
|
578
|
|
Permian/Delaware Basin
|
|
|
280
|
|
|
|
158
|
|
|
|
469
|
|
|
|
394
|
|
South Texas
|
|
|
17
|
|
|
|
34
|
|
|
|
36
|
|
|
|
71
|
|
Total
|
|
|
618
|
|
|
|
439
|
|
|
|
1,271
|
|
|
|
1,043
|
|
Gas production (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountain
|
|
|
496
|
|
|
|
520
|
|
|
|
1,100
|
|
|
|
1045
|
|
Permian/Delaware Basin
|
|
|
316
|
|
|
|
452
|
|
|
|
768
|
|
|
|
971
|
|
South Texas
|
|
|
87
|
|
|
|
146
|
|
|
|
182
|
|
|
|
288
|
|
Total
|
|
|
899
|
|
|
|
1,118
|
|
|
|
2,050
|
|
|
|
2,304
|
|
NGL production (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountain
|
|
|
71
|
|
|
|
84
|
|
|
|
168
|
|
|
|
179
|
|
Permian/Delaware Basin
|
|
|
32
|
|
|
|
34
|
|
|
|
69
|
|
|
|
80
|
|
South Texas
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
3
|
|
Total
|
|
|
103
|
|
|
|
120
|
|
|
|
237
|
|
|
|
262
|
|
Total production (MBoe) (1)
|
|
|
871
|
|
|
|
745
|
|
|
|
1,850
|
|
|
|
1,689
|
|
Average sales price per Bbl of oil (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountain
|
|
$
|
54.66
|
|
|
$
|
62.73
|
|
|
$
|
51.41
|
|
|
$
|
60.05
|
|
Permian/Delaware Basin
|
|
|
55.49
|
|
|
|
61.11
|
|
|
|
52.48
|
|
|
|
61.04
|
|
South Texas
|
|
|
63.08
|
|
|
|
68.84
|
|
|
|
59.74
|
|
|
|
66.21
|
|
Composite
|
|
|
55.25
|
|
|
|
62.62
|
|
|
|
52.04
|
|
|
|
60.84
|
|
Average sales price per Mcf of gas (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountain
|
|
$
|
0.42
|
|
|
$
|
1.30
|
|
|
$
|
1.06
|
|
|
$
|
1.72
|
|
Permian/Delaware Basin
|
|
|
0.08
|
|
|
|
1.35
|
|
|
|
0.40
|
|
|
|
1.58
|
|
South Texas
|
|
|
2.02
|
|
|
|
2.22
|
|
|
|
2.24
|
|
|
|
2.27
|
|
Composite
|
|
|
0.45
|
|
|
|
1.44
|
|
|
|
0.92
|
|
|
|
1.73
|
|
Average sales price per Bbl of NGL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountain
|
|
$
|
3.33
|
|
|
$
|
14.10
|
|
|
$
|
5.79
|
|
|
$
|
14.45
|
|
Permian/Delaware Basin
|
|
|
0.87
|
|
|
|
17.78
|
|
|
|
5.00
|
|
|
|
17.67
|
|
South Texas
|
|
|
0.00
|
|
|
|
23.12
|
|
|
|
15.41
|
|
|
|
21.53
|
|
Composite
|
|
|
2.57
|
|
|
|
15.29
|
|
|
|
5.57
|
|
|
|
15.51
|
|
Average sales price per Boe (2)
|
|
|
39.98
|
|
|
|
41.49
|
|
|
|
37.48
|
|
|
|
42.34
|
|
Average cost of production per Boe produced (3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountain
|
|
$
|
6.51
|
|
|
$
|
7.66
|
|
|
$
|
5.02
|
|
|
$
|
5.97
|
|
Permian/Delaware Basin
|
|
|
12.28
|
|
|
|
6.83
|
|
|
|
13.87
|
|
|
|
5.15
|
|
South Texas
|
|
|
18.03
|
|
|
|
13.98
|
|
|
|
16.27
|
|
|
|
13.62
|
|
Composite
|
|
|
9.33
|
|
|
|
7.87
|
|
|
|
8.61
|
|
|
|
6.22
|
|
|
(1)
|
Oil and gas were combined by converting gas to Boe on the basis of 6 Mcf of gas to 1 Bbl of oil.
|
|
(2)
|
Before the impact of hedging activities.
|
|
(3)
|
Production costs include direct lease operating costs but exclude ad valorem taxes and production taxes.
|
Availability of Capital
.
As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flow from operating activities, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, monetizing of derivative instruments, and if an appropriate opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all. As of
June 30, 2019
, our borrowing base was
$217.5
million with
$34.5
million of availability under our credit facility.
Borrowings and Interest
.
At
June 30, 2019
, we had a total of
$183.0
million outstanding under our credit facility and total indebtedness of
$186.2
million (including the current portion). If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements. As a result, we would need to increase our cash flow from operations in order to fund the development of our drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices.
Exploration and Development Activity.
We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us for future growth. At
December 31, 2018
, we operated properties accounting for approximately 96% of our PV-10, giving us substantial control over the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations on our existing leaseholds, the successful development of which we believe could significantly increase our production and proved reserves.
Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration and development activities will result in increases in our proved reserves. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility may also decline. In addition, approximately 63% of our estimated proved reserves on a Boe basis at
December 31, 2018
were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We may be unable to acquire or develop additional reserves or develop our existing undeveloped reserves, in which case our results of operations and financial condition could be adversely affected.
Operational Update
Williston Basin, North Dakota
In North Dakota, the four-well Lillibridge NW pad (in which we own an average 33 percent working interest) was successfully completed and placed on production. This four well pad has averaged 745 Boepd per well over its first month of production and continues to increase following our choke management protocol.
Raven Rig #1 has commenced drilling operations on our six-well Jore Fed Extension pad, in which we own an average 90 percent working interest. Timing of first production from this pad will depend on weather, oil prices, and gas takeaway capacity.
Delaware Basin, West Texas
Operations in the Delaware Basin of West Texas continue to proceed smoothly. In Winkler County we successfully brought on line the Hackberry #201H (5,000-foot lateral in the Wolfcamp A-1), in which we own a 75 percent working interest. In Ward County, the two-well Woodberry pad (5,000-foot laterals in the Wolfcamp A-1 and 3
rd
Bone Spring) have been completed and are beginning their flowback with encouraging initial production rates. Both wells were drilled and completed under budget. On the Greasewood pad, in which we own 100 percent working interest, two 5,000-foot laterals in the Third Bone Spring and the Wolfcamp B are drilling the lateral sections with frac operations scheduled to commence in September 2019. As the Greasewood wells represent the last remaining obligation wells for the Company for 2019, upon completion, the rig will be released giving us time to work on production optimization on the twenty plus producing wells in the area.
Results of Operations
Selected Operating Data
. The following table sets forth operating data from continuing operations for the periods presented.
|
|
Three Months Ended June 30,
|
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
|
2018
|
|
|
2019
|
|
|
2018
|
|
Operating revenue (1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
34,146
|
|
|
$
|
27,472
|
|
|
$
|
66,127
|
|
|
$
|
63,466
|
|
Gas sales
|
|
|
408
|
|
|
|
1,608
|
|
|
|
1,881
|
|
|
|
3,985
|
|
NGL sales
|
|
|
265
|
|
|
|
1,835
|
|
|
|
1,321
|
|
|
|
4,058
|
|
Other
|
|
|
1
|
|
|
|
1
|
|
|
|
5
|
|
|
|
37
|
|
Total operating revenues
|
|
$
|
34,820
|
|
|
$
|
30,916
|
|
|
$
|
69,334
|
|
|
$
|
71,546
|
|
Operating income
|
|
$
|
8,935
|
|
|
$
|
10,797
|
|
|
$
|
15,643
|
|
|
$
|
30,757
|
|
Oil sales (MBbls)
|
|
|
618
|
|
|
|
439
|
|
|
|
1,271
|
|
|
|
1,043
|
|
Gas sales (MMcf)
|
|
|
899
|
|
|
|
1,118
|
|
|
|
2,050
|
|
|
|
2,304
|
|
NGL sales (MBbls)
|
|
|
103
|
|
|
|
120
|
|
|
|
237
|
|
|
|
262
|
|
Oil equivalents (MBoe)
|
|
|
871
|
|
|
|
745
|
|
|
|
1,850
|
|
|
|
1,689
|
|
Average oil sales price (per Bbl)(1)
|
|
$
|
55.25
|
|
|
$
|
62.62
|
|
|
$
|
52.04
|
|
|
$
|
60.84
|
|
Average gas sales price (per Mcf)(1)
|
|
$
|
0.45
|
|
|
$
|
1.44
|
|
|
$
|
0.92
|
|
|
$
|
1.73
|
|
Average NGL sales price (per Bbl)
|
|
$
|
2.57
|
|
|
$
|
15.29
|
|
|
$
|
5.57
|
|
|
$
|
15.51
|
|
Average oil equivalent sales price (Boe) (1)
|
|
$
|
39.98
|
|
|
$
|
41.49
|
|
|
$
|
37.48
|
|
|
$
|
42.34
|
|
___________________
|
(1)
|
Revenue and average sales prices are before the impact of hedging activities.
|
Comparison of Three Months Ended
June 30, 2019
to Three Months Ended
June 30, 2018
Operating Revenue
. During the three months ended
June 30, 2019
, operating revenue increased to
$34.8
million from
$30.9
million for the same period of
2018
. The increase in revenue was primarily due to higher oil sales volumes, partially offset by lower prices during the three months ended
June 30, 2019
as compared to the same period of
2018
. Higher oil sales volumes slightly offset by lower gas and NGL sales contributed
$11.1
million to operating revenue for the three months ended
June 30, 2019
. Lower realized commodity prices for all products had a negative impact of
$7.2
million on operating revenue.
Oil sales volumes increased to
618
MBbl during the three months ended
June 30, 2019
from
439
MBbl for the same period of
2018
. The increase in oil sales volume was primarily due to new wells brought on line since the second quarter of
2018
, offset by natural field declines and property sales. New wells brought on line since the second quarter of 2018 contributed 353 MBbl for the three months ended
June 30, 2019
. Gas sales volumes decreased to
899
MMcf for the three months ended
June 30, 2019
from
1,118
MMcf for the same period of
2018
. The decrease in gas production was primarily due to field declines and continued pipeline constraints in West Texas and North Dakota, partially offset by new wells brought on line since the second quarter of
2018
which contributed 266 MMcf for the three months ended
June 30, 2019
. NGL sales volumes decreased to
103
MBbl for the three months ended
June 30, 2019
from
120
MBbl for the same period of
2018
. The decrease in NGL sales corresponds to the decrease in gas sales.
Lease Operating Expenses (“LOE”)
.
LOE for the three months ended
June 30, 2019
increased to
$8.1
million from
$5.7
million for the same period in
2018
. The increase in LOE was primarily due to higher cost of services and new wells brought onto production since
June 30, 2018
as well as significant non-recurring cost related to the cost of shutting-in wells for frac protection and repair of frac damage to wells from offset fracs. LOE per Boe for the three months ended
June 30, 2019
was
$9.26
compared to
$7.69
for the same period of
2018
. The increase per Boe was due to higher costs offset by higher sales volumes for the three months ended
June 30, 2019
as compared to the same period of
2018
.
Production and Ad Valorem Taxes.
Production and ad valorem taxes for the three months ended
June 30, 2019
increased to
$2.9
million from
$2.5
million for the same period of
2018
. Production and ad valorem taxes for the three months ended
June 30, 2019
and 2018 were 8% of total oil, gas and NGL sales.
General and Administrative (“G&A”) Expense.
G&A expenses, excluding stock-based compensation, was generally flat at
$2.2
million for the three months ended
June 30, 2019
and 2018. G&A expense per Boe, excluding stock-based compensation, was
$2.51
for the quarter ended
June 30, 2019
compared to
$2.93
for the same period of
2018
. The decrease per Boe was primarily due to higher sales volumes.
Stock-Based Compensation.
Options granted to employees and directors are valued at the date of grant and expense is recognized over the options' vesting period. In addition to options, restricted shares of the Company’s common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the three months ended
June 30, 2019
, stock-based compensation expense was
$0.5
million compared to
$0.9
million for the same period of
2018
.
Depreciation, Depletion and Amortization (“DD&A”) Expense.
DD&A expense, including accretion of future site development, for the three months ended
June 30, 2019
increased to
$12.2
million from
$8.8
million for the same period of
2018
. The increase was primarily due to higher future development cost included in the
June 30, 2019
reserve report, capital expenditures in the first six months of 2019, as well as higher production volumes during the three months ended
June 30, 2019
as compared to the same period of
2018
. DD&A expense per Boe for the three months ended
June 30, 2019
was
$13.99
compared to
$11.86
in
2018
. The increase in DD&A expense per Boe was primarily due to a higher full cost pool as well as higher capital cost in relation to reserve additions.
Ceiling Limitation Write-Down
.
We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity and reported earnings. As of
June 30, 2019
, and
June 30, 2018
, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.
The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves. We cannot assure you that we will not experience additional write-downs in the future. If commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our oil and gas properties may be required.
Interest Expense.
Interest
expense for the three months ended
June 30, 2019
increased to
$2.8
million compared to
$1.5
million for the same period of
2018
. The increase in interest expense in 2019 was due to higher levels of debt during the three months ended
June 30, 2019
as compared to the same period in
2018
, as well as higher interest rates in 2019 as compared to
2018
. For the three months ended
June 30, 2019
the interest rate on our credit facility averaged
6.0%
as compared to
5.1%
for the same period of
2018
.
Loss (Gain) on Derivative Contracts
.
Derivative gains or losses are determined by actual derivative settlements during the period and on the periodic mark to market valuation of derivative contracts in place at period end. We have elected not to apply hedge accounting to our derivative contracts; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps as of
June 30, 2019
, and June 30, 2018. The net estimated value of our commodity derivative contracts was a net liability of approximately
$6.4
million as of
June 30, 2019
. When our derivative contract prices are higher than prevailing market prices, we incur gains and, conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the three months ended
June 30, 2019
, we recognized a gain on our commodity derivative contracts of
$5.6
million, consisting of a loss on closed contracts of
$1.9
million and a gain of
$7.5
million related to open contracts. For the three months ended
June 30, 2018
, we recognized a loss on our commodity derivative contracts of
$19.8
million, consisting of a loss of
$6.1
million on closed contracts and a loss of
$13.7
million related to open contracts.
Income Tax Expense.
For the three months ended
June 30, 2019
and
June 30, 2018
there was no income tax expense recognized due to our NOL carryforwards.
Comparison of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2018
Operating Revenue
. During the six months ended June 30, 2019, operating revenue decreased to
$69.3
million from
$71.5
million for the same period of 2018. The decrease in revenue was primarily due to lower prices for all products offset by higher oil sales volumes during the six months ended June 30, 2019 as compared to the same period of 2018. Lower realized commodity prices for all products negatively impacted operating revenue by
$15.7
million of which $11.2 million was attributable to oil. Lower gas and NGL prices had a negative impact on revenue of approximately $4.5 million for the six months ended June 30, 2019. During the six months ended June 30, 2019 gas and NGL sales were impacted by a very weak pricing environment as well as plant and pipeline constraints. Higher oil sales volumes contributed
$13.8
million to operating revenue for the six months ended June 30, 2019 offset by lower gas and NGL sales which negatively impacted revenue by $0.4 million.
Oil sales volumes increased to
1,271
MBbl during the six months ended June 30, 2019 from 1,043 MBbl for the same period of 2018. The increase in oil sales volume was primarily due to new wells brought on line since the second quarter of 2018, offset by natural field declines and property sales. New wells brought on line since the second quarter of 2018 contributed 681 MBbl for the six months ended June 30, 2019. Gas sales volumes decreased to
2,050
MMcf for the six months ended June 30, 2019 from 2,304 MMcf for the same period of 2018. The decrease in gas and NGL sales was primarily due to a lack of infrastructure and pipeline and plant constraints offset by new wells brought on line since the second quarter of 2018 which contributed 520 MMcf for the six months ended June 30, 2019. NGL sales volumes decreased to
237
MBbl for the six months ended June 30, 2019 from
262
MBbl for the same period of 2018. The decrease in NGL sales corresponds to the decrease in gas sales.
Lease Operating Expenses (“LOE”)
.
LOE for the six months ended June 30, 2019 increased to
$15.8
million from $10.3 million for the same period in 2018. The increase in LOE was primarily due to higher cost of services and new wells brought onto production since June 30, 2018 as well as significant non-recurring cost related to the cost of shutting-in wells for frac protection and repair of frac damage to wells from offset fracs. LOE per Boe for the six months ended June 30, 2019 was
$8.54
compared to
$6.10
for the same period of 2018. The increase per Boe was due to higher costs offset by higher sales volumes for the six months ended June 30, 2019 as compared to the same period of 2018.
Production and Ad Valorem Taxes.
Production and ad valorem taxes for the six months ended June 30, 2019 increased to
$6.0
million from $5.6 million for the same period in 2018. The increase was primarily due to higher production volumes. Production and ad valorem taxes for the six months ended June 30, 2019 were 9% of total oil, gas and NGL sales compared to 8% for the same period of 2018. The increase in the percentage of taxes of total oil, gas and NGL sales was due to increased production in North Dakotas which has a higher tax rate.
General and Administrative (“G&A”) Expense.
G&A expenses, excluding stock-based compensation, increased to
$4.5
million for the six months ended June 30, 2019 compared to
$4.3
million for the same period of 2018. G&A expense per Boe, excluding stock-based compensation, was
$2.45
for the six months ended June 30, 2019 compared to
$2.56
for the same period of 2018. The decrease per Boe was primarily due to higher G&A expense offset by higher sales volumes.
Stock-Based Compensation.
Options granted to employees and directors are valued at the date of grant and expense is recognized over the options' vesting period. In addition to options, restricted shares of the Company’s common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the six months ended June 30, 2019 stock-based compensation expense was
$0.9
million compared to
$1.5
million for the same period of 2018. The decrease is due to grants that have fully vested and the related expense already recognized.
Depreciation, Depletion and Amortization (“DD&A”) Expense.
DD&A expense, including accretion of future site development, for the six months ended June 30, 2019 increased to
$25.8
million from $19.1 million for the same period of 2018. The increase was primarily due to higher future development costs included in the
June 30, 2019
reserve report, capital expenditures in the first six months of 2019, as well as higher production volumes during the three months ended
June 30, 2019
as compared to the same period of
2018
. DD&A expense per Boe for the six months ended June 30, 2019 was
$13.93
compared to $11.31 in 2018. The increase was primarily the result of higher future development costs.
Ceiling Limitation Write-Down
.
We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity and reported earnings. As of June 30, 2019, and June 30, 2018, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.
The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves. We cannot assure you that we will not experience additional write-downs in the future. If commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our oil and gas properties may be required.
Interest Expense.
Interest
expense for the six months ended June 30, 2019 increased to
$5.7
million compared to
$2.7
million for the same period of 2018. The increase in interest expense in 2019 was due to higher levels of debt during the six months ended June 30, 2019 as compared to the same period in 2018 as well as higher interest rates in 2019 as compared to 2018. The average interest rate during the six months ended June 30, 2019 was
6.0%
compared to
5.0%
for the same period of 2018.
Loss (Gain) on Derivative Contracts
.
Derivative gains or losses are determined by actual derivative settlements during the period and on the periodic mark to market valuation of derivative contracts in place. We have elected not to apply hedge accounting to our derivative contracts; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts as of June 30, 2019 and 2018 consisted of NYMEX-based fixed price swaps and basis differential swaps. The net estimated value of our commodity derivative contracts was a net liability of approximately
$6.4
million as of June 30, 2019. When our derivative contract prices are higher than prevailing market prices, we incur gains and, conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the six months ended June 30, 2019, we recognized a loss on our commodity derivative contracts of
$23.4
million, consisting of a loss on closed contracts of
$2.8
million and a loss of
$20.6
million related to open contracts. For the six months ended June 30, 2018, we recognized a loss on our commodity derivative contracts of $27.6 million, consisting of a loss of $9.8 million on closed contracts and a loss of $17.8 million related to open contracts.
Income Tax Expense.
For the six months ended June 30, 2019 and 2018 there was no income tax expense recognized as a result of our NOL carryforwards.
Liquidity and Capital Resources
General
. The oil and gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to service debt and to fund the following:
|
•
|
the development and exploration of existing properties, including drilling and completion costs of wells;
|
|
•
|
acquisition of interests in additional oil and gas properties; and
|
|
•
|
production and transportation facilities.
|
The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, will directly affect our ability to service our debt obligations and to grow the business through the development of existing properties and the acquisition of new properties.
Our principal sources of capital are cash flow from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, monetizing of derivative contracts and if appropriate opportunities are available, the sale of debt or equity securities, although we may not be able to complete any such transactions on terms acceptable to us, if at all. Based upon current oil, gas and NGL price expectations and our commodity derivatives positions, we anticipate that our cash on hand, cash flow from operations and available borrowing capacity under our revolving credit facility will provide us sufficient liquidity to fund our operations for the remainder of
2019
including our planned capital expenditures.
Working Capital (Deficit)
. At
June 30, 2019
, our current liabilities of
$67.8
million exceeded our current assets of
$32.0
million resulting in a working capital deficit of
$35.8
million. This compares to a working capital deficit of
$13.6
million at December 31, 2018. Current assets at
June 30, 2019
primarily consisted of accounts receivable of
$30.7
million, current amount of our derivative asset of
$0.5
million and other current assets of
$0.8
million. Current liabilities at
June 30, 2019
primarily consisted of trade payables of
$41.1
million, revenues due third parties of
$17.1
million, current maturities of long-term debt of
$0.3
million, the current amount of our derivative liability of
$7.8
million and accrued expenses and other of
$1.6
million. The working capital deficit is expected to be funded by cash flows from operations and borrowings under our credit facility.
Capital Expenditures
. Capital expenditures for the
six months ended June 30, 2019
and
2018
were $63.6 million and $76.1 million, respectively.
The table below sets forth the components of these capital expenditures:
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
|
2018
|
|
|
|
(In thousands)
|
|
Expenditure category:
|
|
|
|
|
|
|
|
|
Exploration/Development
|
|
$
|
63,483
|
|
|
$
|
53,623
|
|
Acquisitions
|
|
|
-
|
|
|
|
21,769
|
|
Facilities and other
|
|
|
94
|
|
|
|
729
|
|
Total
|
|
$
|
63,577
|
|
|
$
|
76,121
|
|
During the
six months ended June 30, 2019
our expenditures were primarily for development of our existing properties. For the six months ended June 30, 2018, expenditures were primarily for the development of our existing properties and the acquisition of leaseholds. Capital expenditures for the six months ended June 30, 2019 of $63.6 million includes $3.2 million for a decrease in capital expenditures in accounts payable, net capital expenditures of $60.4 million was applicable to our 2019 capital expenditures budget. We anticipate making capital expenditures in
2019
of approximately $86.0 million, of which approximately $47.0 million is allocated to acquiring additional acreage and developing our Bone Spring/Wolfcamp acres in the Permian/Delaware Basin. The
2019
budget also allocates approximately $27.0 million for developing our Williston Basin/Bakken/Three Forks play in North Dakota, with the remaining amount allocated to acquisitions, facilities and general corporate purposes. The
2019
capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources, our financial results and our ability to obtain permits for drilling locations. Our capital expenditures could also include expenditures for the acquisition of producing properties, if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows from operations will decrease which may result in a reduction of the capital expenditure budget. If we decrease our capital expenditure budget, we may not be able to offset oil and gas production decreases caused by natural field declines.
Sources of Capital.
The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
|
|
Six Months Ended June 30,
|
|
|
|
2019
|
|
|
2018
|
|
|
|
(In thousands)
|
|
Net cash provided by operating activities
|
|
$
|
42,699
|
|
|
$
|
45,286
|
|
Net cash used in investing activities
|
|
|
(46,772
|
)
|
|
|
(73,709
|
)
|
Net cash provided by financing activities
|
|
|
3,206
|
|
|
|
27,687
|
|
Total
|
|
$
|
(867
|
)
|
|
$
|
(736
|
)
|
Operating activities for the
six months ended June 30, 2019
provided $42.7 million in cash compared to providing $45.3 million in the same period of
2018
. Reductions in operating income offset by changes in operating assets and liabilities accounted for most of these funds. Investing activities used $46.8 million during the
six months ended June 30, 2019
primarily for the development of our existing properties. Investing activities used $73.7 million during the
six months ended June 30, 2018
primarily for the development of our existing properties and acquisition of leasehold, partially offset by proceeds from the sale of oil and gas properties. Financing activities provided $3.2 million for the
six months ended June 30, 2019
compared to providing $27.7 million for the same period of
2018
. Funds provided during the
six months ended June 30, 2019
and 2018, were primarily net proceeds from borrowings under our credit facility.
Future Capital Resources
. Our principal sources of capital going forward are cash flows from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, monetizing derivative instruments and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all.
Cash from operating activities is dependent upon commodity prices and production volumes. Depressed commodity prices have reduced, and further decreases in commodity prices from current levels could reduce our cash flows from operations. This could cause us to alter our business plans, including reducing our exploration and development plans. Unless we otherwise expand and develop reserves, our production volumes may decline as reserves are produced. In the future, we may continue to sell producing properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful exploration and development activities, acquire additional producing properties or identify and develop additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase our production volumes; however, our drilling activities are subject to numerous risks, including availability of capital and the risk that no commercially productive oil and gas reservoirs will be found. If our proved reserves decline in the future, our production could also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility could also decline. The risk of not finding commercially productive reservoirs will be compounded by the fact that 63% of our total estimated proved reserves on a Boe basis at
December 31, 2018
were classified as undeveloped.
We have in the past, and may in the future, sell producing properties. We have also sold debt and equity securities in the past, and may sell additional debt and equity securities in the future when the opportunity presents itself.
Contractual Obligations.
We are committed to making cash payments in the future on the following types of agreements:
Below is a schedule of the future payments that we are obligated to make based on agreements in place as of
June 30, 2019
:
|
|
Payments due in twelve month periods ending:
|
|
Contractual Obligations
|
|
Total
|
|
|
June 30, 2020
|
|
|
June 30, 2021-2022
|
|
|
June 30, 2023-2024
|
|
|
Thereafter
|
|
Long-term debt (1)
|
|
$
|
186,227
|
|
|
$
|
274
|
|
|
$
|
183,590
|
|
|
$
|
2,363
|
|
|
$
|
-
|
|
Interest on long-term debt (2)
|
|
|
30,523
|
|
|
|
10,585
|
|
|
|
19,823
|
|
|
|
115
|
|
|
|
-
|
|
Lease obligations (3)
|
|
|
513
|
|
|
|
284
|
|
|
|
119
|
|
|
|
68
|
|
|
|
42
|
|
Total
|
|
$
|
217,263
|
|
|
$
|
11,143
|
|
|
$
|
203,532
|
|
|
$
|
2,546
|
|
|
$
|
42
|
|
|
(1)
|
These amounts represent the balances outstanding under our credit facility and the real estate lien note. These payments assume that we will not borrow additional funds.
|
|
(2)
|
Interest expense assumes the balances of long-term debt at the end of the period and current effective interest rates.
|
We maintain a reserve for costs associated with future site restoration related to the retirement of tangible long-lived assets. At
June 30, 2019
, our reserve for these obligations totaled $7.8 million for which no contractual commitments exist. For additional information relating to this obligation, see Note 1 of the Notes to Condensed Consolidated Financial Statements.
Off-Balance Sheet Arrangements.
At
June 30, 2019
, we had no existing off-balance sheet arrangements, as defined under SEC regulations, that 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 that are material to investors.
Contingencies.
From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At
June 30, 2019
, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.
Long-Term Indebtedness.
Long-term debt consisted of the following:
|
|
June 30, 2019
|
|
|
December 31, 2018
|
|
Credit facility
|
|
$
|
183,000
|
|
|
$
|
180,000
|
|
Real estate lien note
|
|
|
3,227
|
|
|
|
3,358
|
|
|
|
|
186,227
|
|
|
|
183,358
|
|
Less current maturities
|
|
|
(274
|
)
|
|
|
(267
|
)
|
|
|
$
|
185,953
|
|
|
$
|
183,091
|
|
Credit Facility
The Company has a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility. As of
June 30, 2019
,
$183.0
million was outstanding under the Credit Facility.
The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. At
June 30, 2019
, we had a borrowing base of
$217.5
million. The borrowing base is determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves securing the facility utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we are able to request one redetermination during any six-month period between scheduled redeterminations. Outstanding borrowings in excess of the borrowing base must be repaid immediately or we must pledge additional oil and gas properties or other assets as collateral. We do not currently have any substantial unpledged assets and we may not have the financial resources to make any mandatory principal payments. In addition, a reduction of the borrowing base could also cause us to fail to be in compliance with the financial covenants described below. The borrowing base will be automatically reduced in connection with any sales of producing properties with a market value of 5% or more of our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the credit facility bear interest at (a) at any time an event of default exists, at 3% per annum plus the amounts set forth below, and (b) at all other times, at the greater of (x) the reference rate announced from time to time by Société Générale, (y) the Federal Funds Rate plus 0.5%, and (z) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (i) 1.5%-2.5%, depending on the utilization of the borrowing base, or, (ii) if we elect, LIBOR plus, in each case, 2.5%-3.5% depending on the utilization of the borrowing base. At
June 30, 2019
, the interest rate on the credit facility was approximately 5.7% assuming LIBOR borrowings.
Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is May 16, 2021. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. We are permitted to terminate the credit facility and are able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.
Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets. The collateral is required to include properties comprising at least 90% of the PV-10 of our proven reserves. We have also granted our lenders a security interest in our headquarters building.
Under the credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are required to maintain a current ratio, as defined in the credit facility, as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio of not less than 2.50 to 1.00. We are also required as of the last day of each quarter to maintain a total debt to EBITDAX ratio of not more than 3.50 to 1.00. The current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20 and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20. The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is defined as the sum of consolidated net income plus interest expense, oil and gas exploration expenses, income and franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts plus expenses incurred in connection with the negotiation, execution, delivery and performance of the credit facility plus expenses incurred in connection with any acquisition permitted under the credit facility plus expenses incurred in connection with any offering of senior unsecured notes, subordinated debt or equity plus up to $1.0 million of extraordinary expenses in any 12-month period plus extraordinary losses minus all non-cash items of income which were included in determining consolidated net loss, including all non-cash items resulting from the application of ASC 815 and ASC 410-20. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with our headquarters building and obligations with respect to surety bonds and derivative contracts
.
At
June 30, 2019
, we were in compliance with all of these financial covenants. As of
June 30, 2019
, the interest coverage ratio was
8.12
to 1.00, the total debt to EBITDAX ratio was
2.24
to 1.00, and our current ratio was
1.10
to 1.00.
The credit facility contains a number of covenants that, among other things, restrict our ability to:
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•
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incur or guarantee additional indebtedness;
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•
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transfer or sell assets;
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•
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create liens on assets;
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•
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engage in transactions with affiliates other than on an “arm’s length” basis;
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•
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make any change in the principal nature of our business; and
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•
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permit a change of control.
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The credit facility also contains certain additional covenants including requirements that:
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•
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100% of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility; and
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•
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if the sum of our cash on hand plus liquid investments exceeds $10.0 million, then the amount in excess of $10.0 million must be used to pay amounts outstanding under the credit facility.
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The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. As of
June 30, 2019
, we were in compliance with all of the terms of our credit facility.
Real Estate Lien Note
We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The note was modified on June 20, 2018 to a fixed rate of 4.9% and is payable in monthly installments of $35,672. The maturity date of the note is July 20, 2023. As of
June 30, 2019
and
December 31, 2018
, $3.2 million and $3.4 million, respectively, were outstanding on the note.
Hedging Activities
Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. We have entered into commodity swaps on approximately 85% of our estimated oil production from our net proved developed producing reserves (based on reserve estimates at
December 31, 2018
) from July 1 through December 31, 2019, 85% for 2020 and 75% for 2021.
By removing a portion of price volatility on our future oil and gas production, we believe that we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations. However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow on the portion of the production that has been hedged. We have sustained, and in the future, will sustain, losses on our derivative contracts when market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain gains on our commodity derivative contracts.
If the disparity between our contract prices and market prices continues, we will sustain gains or losses on our derivative contracts. While gains and losses resulting from the periodic mark to market of our open contracts do not impact our cash flow from operations, gains and losses from settlements of our closed contracts do impact our cash flow from operations.
In addition, as our derivative contracts expire over time, we expect to enter into new derivative contracts at then-current market prices. If the prices at which we hedge future production are significantly lower than our existing derivative contracts, our future cash flow from operations would likely be materially lower.