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, 2016 filed with the SEC on March 16, 2017, 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, 2016.
General
We are an independent energy company primarily engaged in the acquisition, exploration, exploitation, development and production of oil and gas in the United States. Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties, principally through the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling. 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 and exploration 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:
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•
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commodity prices and the effectiveness of our hedging arrangements;
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•
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the level of total sales volumes of oil and gas;
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•
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the availability of and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;
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•
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the level of and interest rates on borrowings; and
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•
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the level and success of exploration and development activity.
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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 this volatility is expected to continue. 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 2017 will impact the amount of cash generated from operating activities, which will in turn impact our financial position.
During the nine months ended
September 30, 2017
, the NYMEX future price for oil averaged
$49.39
per Bbl as compared to
$41.54
per Bbl in 2016. During the nine months ended
September 30, 2017
, the NYMEX future spot price for gas averaged
$3.21
per MMBtu compared to
$2.35
per MMBtu in 2016. Prices closed on
September 30, 2017
at
$51.67
per Bbl of oil and
$3.01
per MMBtu of gas, compared to closing on
September 30, 2016
at
$48.24
per Bbl of oil and
$2.91
per MMBtu of gas. On November 6, 2017, prices closed at $57.35 per Bbl of oil and $3.13 per MMBtu of gas. If commodity prices decline, our revenue and cash flow from operations will also likely decline. In addition, lower commodity prices could also reduce the amount of oil and gas that we can produce economically. If oil and gas prices decline, our revenues, profitability and cash flow from operations will also likely decrease which could cause us to alter our business plans, including reducing our drilling activities. Such declines have required, and in future periods could also require us to write down the carrying value of our oil and gas assets which would also cause a reduction in net income. Finally, low commodity prices will likely cause a reduction of the borrowing base under our credit facility.
The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to:
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basis differentials which are dependent on actual delivery location;
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adjustments for BTU content;
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quality of the hydrocarbons; and
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gathering, processing and transportation costs.
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The following table sets forth our average differentials for the nine months ended
September 30, 2017
and 2016:
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Oil - NYMEX
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Gas - NYMEX
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2017
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2016
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2017
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2016
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Average realized price (1)
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$
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44.44
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$
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34.13
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$
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1.79
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$
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1.10
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Average NYMEX price
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49.39
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41.54
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3.21
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2.35
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Differential
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$
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(4.95
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)
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$
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(7.41
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)
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$
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(1.42
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)
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$
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(1.25
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)
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_____________________________________
(1) Excludes the impact of derivative activities.
At
September 30, 2017
, our derivative contracts consisted of NYMEX-based fixed price swaps, basis differential swaps and collar contracts. Under fixed price swaps, we receive a fixed price for our production and pay a variable market price to the contract counter-party. Under a basis differential swap, if the market price is above the fixed price we pay the counter-party, if the market price is below the fixed price, the counter-party pays us. Under a collar contract, we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor price (long put).
Our derivative contracts equate to approximately 75% of the estimated oil production from our net proved developed producing reserves (based on reserve estimates at September 30, 2017) from October 1, 2017 through December 31, 2017, 75% in 2018 and 48% in 2019. As of
September 30, 2017
, we also had NYMEX-based costless collar commodity arrangements on approximately 46% of our estimated net proved developed producing gas reserves (based on reserve estimates at September 30, 2017) from October 1, 2017 through December 31, 2017 and a 500 Boepd Midland - Cushing oil price differential swap at ($0.65)/Bbl. 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 nine months ended
September 30, 2017
, we realized a gain of
$10.4 million
, consisting of a gain of
$3.4 million
on closed contracts and a gain of
$7.0 million
related to open contracts. For the nine months ended
September 30, 2016
, we realized a loss of
$10.3 million
consisting of a gain of
$3.2 million
on closed contracts and a loss of
$13.5 million
related to open contracts. We have not designated any of these derivative contracts as hedges as prescribed by applicable accounting rules.
The following table sets forth our derivative contracts at
September 30, 2017
:
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Oil - WTI
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Contract Periods
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Daily Volume (Bbl)
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Swap Price (per Bbl)
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Fixed Swaps
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2017
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4,062
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$
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52.82
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2018
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2,649
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$
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48.53
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2019
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1,200
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$
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54.54
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Basis Swap
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2017
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500
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$
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0.65
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Gas
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Contract Period
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Daily Volume (Mcf)
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Floor (Put)
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Ceiling (Call)
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Collar Contracts
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2017
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5,000
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$
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3.00
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$
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3.90
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At
September 30, 2017
, the aggregate fair market value of our commodity derivative contracts was a net liability of approximately
$1.0 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, 2016, our average annual estimated decline rate for our net proved developed producing reserves is 40%; 15%; 12%; 11% and 9% in 2018, 2019, 2020, 2021 and 2022, respectively, 9% in the following five years, and approximately 9% 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 nine months ended
September 30, 2017
of
$91.4 million
related to our exploration and development activities as well as the acquisition of leasehold. We have a capital expenditure budget for 2017 of approximately $120.0 million consisting of $110.0 million in cash with the remainder being equity and land swap value. Approximately $71.3 million of the 2017 budget is allocated to developing our Permian/Delaware Basin assets and expanding our acreage position in the Delaware Basin. The 2017 budget also allocates approximately $42.2 million for drilling and completion of wells in our Williston Basin/Bakken/Three Forks play in North Dakota, with the remaining amount allocated to the Austin Chalk/Eagle Ford area in South Texas as well as lease acquisition and general corporate expenses. The 2017 capital expenditure budget is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil and gas, the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, the availability of sufficient capital resources, the results of our exploitation efforts, and our ability to obtain permits for drilling locations.
The following table presents historical net production volumes for the three and nine months ended
September 30, 2017
and 2016:
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Three Months Ended
September 30,
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Nine Months Ended
September 30,
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2017
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2016
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2017
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2016
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Total production (MBoe)
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805
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548
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1,889
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1,531
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Average daily production (Boepd)
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8,745
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5,955
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6,920
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5,586
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% Oil
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60
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%
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|
61
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%
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|
57
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%
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|
60
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%
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|
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. In January 2017, we completed a stock offering of 28.8 million shares of common stock for net proceeds of approximately $65.2 million. The net proceeds from this offering were used to repay borrowings under our credit facility. As of
September 30, 2017
, our borrowing base was $115.0 million with
$51.0 million
of availability under our credit facility. Effective November 6, 2017 in connection with the fall redetermination, the borrowing base was increased to
$135.0 million
.
Borrowings and Interest
.
At
September 30, 2017
, we had a total of
$64.0 million
outstanding under our credit facility and total indebtedness of
$67.7 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, 2016, we operated properties accounting for approximately 95% 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. Over the five years ended December 31, 2016, we drilled or participated in 124 gross (46.2 net) wells of which 97% were commercially productive.
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 66% of our estimated proved reserves on a Boe basis (33% on a PV-10 basis) at December 31, 2016 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
Delaware Basin
In Ward County, we successfully completed the Caprito 83-304H, targeting the Wolfcamp A2 formation. We are flowing back the well using a more conservative choke management protocol. We completed 10 stages on the Caprito 83-404H before being impacted by a mechanical issue. We remedied the issue and the remaining 17 stages on the well are now scheduled to be completed in mid-December. We own a 100% working interest in the Caprito 83-304H and 83-404H.
We recently drilled and cased the Caprito 82-101H and 82-202H, in which we own a 100% and 57.1% working interest, respectively. These wells are scheduled for a November completion. We recently set surface casing on all four wells on the Company’s 660’ downspacing test at Caprito. The four-well downspacing test will consist of two Wolfcamp A2 wells, the Caprito 99-301H and Caprito 99-311H, and two Wolfcamp A1 wells, the Caprito 99-202H and Caprito 99-211H. With success, our well spacing will move from four wells per section to the industry norm of up to eight wells per section in the Wolfcamp A1 and A2. We will hold a 57.8% working interest in the Caprito 99-301H, Caprito 99-311H, Caprito 99-202H and Caprito 99-211H.
Williston Basin
In McKenzie County, North Dakota, we are currently completing the Yellowstone 2H-4HR three-well pad in which own a 52% working interest. We are currently drilling the Yellowstone 5H-7H wells in which we own a 52% working interest.
South Texas
In Atascosa County, Texas, we recently completed and began the flowback of the Shut Eye 1H. We own a 100% working interest in the Shut Eye 1H.
Outlook
Market prices for oil, gas and NGL are inherently volatile. Accordingly, we cannot predict with certainty the future prices for the commodities we produce and sell. Current market fundamentals indicate prices for oil, gas and NGL will be higher than experienced during much of 2016, although remaining much lower than prices prior to mid-2014. Lower prices for oil and gas have had and will likely continue to have a material adverse effect on our results of operations and liquidity.
Our primary sources of liquidity are cash flow from operations and borrowings under our credit facility. Cash flow from operations is sensitive to many variables, the most volatile of which is the price of the oil, gas and NGL we produce and sell. Lower prices and/or lower production will cause our cash flow from operations to decrease. Availability under our credit facility is currently subject to a borrowing base which, effective November 6, 2017, was
$135.0 million
. The borrowing base is subject to scheduled semiannual (April 1 and October 1) and other elective borrowing base redeterminations. 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. The lenders under our credit facility can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our credit facility. As a result of the decline in commodity prices for oil, gas and NGL, our borrowing base was reduced in 2016. If prices were to decline again in 2017 or in the future, we could possibly experience a decrease in the borrowing base.
In 2016, as a result of the sharp decline in commodity prices, we incurred impairments to our proved properties of $67.6 million. If commodity prices decrease in the future, we would likely incur additional impairments.
Results of Operations
Selected Operating Data
. The following table sets forth operating data from continuing operations for the periods presented.
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Three Months Ended
September 30,
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Nine Months Ended
September 30,
|
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2017
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2016
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2017
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2016
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|
Operating revenue (1):
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|
|
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|
Oil sales
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|
$
|
21,339
|
|
|
$
|
12,713
|
|
|
$
|
48,153
|
|
|
$
|
31,380
|
|
|
Gas sales
|
|
1,873
|
|
|
1,014
|
|
|
4,918
|
|
|
2,444
|
|
|
NGL sales
|
|
1,495
|
|
|
245
|
|
|
3,559
|
|
|
693
|
|
|
Other
|
|
15
|
|
|
4
|
|
|
46
|
|
|
31
|
|
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Total operating revenues
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|
$
|
24,722
|
|
|
$
|
13,976
|
|
|
$
|
56,676
|
|
|
$
|
34,548
|
|
|
Operating income (loss)
|
|
$
|
5,654
|
|
|
$
|
(4,952
|
)
|
|
$
|
11,867
|
|
|
$
|
(76,993
|
)
|
|
Oil sales (MBbls)
|
|
485
|
|
|
334
|
|
|
1,084
|
|
|
919
|
|
|
Gas sales (MMcf)
|
|
1,105
|
|
|
765
|
|
|
2,754
|
|
|
2,232
|
|
|
NGL sales (MBbls)
|
|
136
|
|
|
86
|
|
|
347
|
|
|
239
|
|
|
Oil equivalents (MBoe)
|
|
805
|
|
|
548
|
|
|
1,889
|
|
|
1,531
|
|
|
Average oil sales price (per Bbl)(1)
|
|
$
|
44.01
|
|
|
$
|
38.08
|
|
|
$
|
44.44
|
|
|
$
|
34.13
|
|
|
Average gas sales price (per Mcf)(1)
|
|
$
|
1.70
|
|
|
$
|
1.32
|
|
|
$
|
1.79
|
|
|
$
|
1.10
|
|
|
Average NGL sales price (per Bbl)
|
|
$
|
11.03
|
|
|
$
|
2.83
|
|
|
$
|
10.27
|
|
|
$
|
2.90
|
|
|
Average oil equivalent sales price (Boe) (1)
|
|
$
|
30.71
|
|
|
$
|
25.50
|
|
|
$
|
29.98
|
|
|
$
|
22.55
|
|
|
___________________
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|
(1)
|
Revenue and average sales prices are before the impact of hedging activities.
|
Comparison of Three Months Ended September 30, 2017 to Three Months Ended September 30, 2016
Operating Revenue
. During the three months ended
September 30, 2017
, operating revenue increased to
$24.7 million
from
$14.0 million
for the same period of 2016. The increase in revenue was due to higher prices for all products as well as higher sales volumes. Higher realized commodity prices contributed $4.4 million to operating revenue, of which $2.9 million was attributable to oil. Higher sales volumes contributed $6.3 million to operating revenue for the three months ended
September 30, 2017
.
Oil sales volumes increased to
485
MBbl during the three months ended
September 30, 2017
from
334
MBbl for the same period of 2016. The increase in oil sales volume was primarily due to new wells brought on line since the third quarter of 2016, offset by natural field declines and property sales. New wells brought on line since the third quarter of 2016 contributed 257 MBbl for the three months ended
September 30, 2017
. Gas sales volumes increased to
1,105
MMcf for the three months ended
September 30, 2017
from
765
MMcf for the same period of 2016. The increase in gas production was due to new wells brought on line since the third quarter of 2016 which contributed 286 MMcf for the three months ended
September 30, 2017
, which was partially offset by natural field declines as well as pipeline constraints. NGL sales volumes increased to
136
MBbl for the three months ended
September 30, 2017
from
86
MBbl for the same period of 2016. The increase in NGL sales was primarily due to more gas production in the Rocky Mountain region which has a higher NGL content.
Lease Operating Expenses (“LOE”)
.
LOE for the three months ended
September 30, 2017
decreased to
$4.1 million
from
$4.6 million
for the same period in 2016. The decrease in LOE was primarily due to lower cost of services and less non-recurring LOE in the third quarter of 2017. Additionally, we have focused on lowering LOE and shutting in marginal wells, as well as sales of non-core properties. LOE per Boe for the three months ended
September 30, 2017
was
$5.08
compared to
$8.40
for the same period of 2016. The decrease per Boe was due to lower service costs and higher sales volumes for the three months ended
September 30, 2017
as compared to the same period of 2016.
Production and Ad Valorem Taxes.
Production and ad valorem taxes for the three months ended
September 30, 2017
increased to
$2.0 million
from
$1.2 million
for the same period in 2016. The increase wasw primarily due to higher commodity prices and production volumes. Production and ad valorem taxes for the three months ended
September 30, 2017
were 8% of total oil, gas and NGL sales compared to 9% for the same period of 2016. The absolute increase in production taxes per Boe was due to higher sales volumes as well as higher realized commodity prices.
General and Administrative (“G&A”) Expense.
G&A expenses, excluding stock-based compensation increased to
$4.3 million
for the three months ended
September 30, 2017
compared to
$2.0 million
for the same period of 2016. The increase was primarily due to one-time discretionary bonus awards in the quarter ended September 30, 2017. G&A expense per Boe, excluding stock-based compensation, was
$5.35
for the quarter ended
September 30, 2017
compared to
$3.64
for the same period of 2016. The increase 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 three months ended
September 30, 2017
and September 30, 2016 stock-based compensation expense was
$0.8 million
.
Depreciation, Depletion and Amortization (“DD&A”) Expense.
DD&A expense for the three months ended
September 30, 2017
increased to
$7.9 million
from
$6.4 million
for the same period of 2016. The increase was primarily due to increased production for the three months ended
September 30, 2017
as compared to the same period of 2016. DD&A expense per Boe for the three months ended
September 30, 2017
was
$9.79
compared to
$11.63
in 2016. The decrease was primarily the result of a reduction in the full cost pool as a result of impairments in 2016 offset by higher sales volumes in the first nine months of 2017 as compared to the same period on 2016.
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
September 30, 2017
, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves. As of September 30, 2016, the net capitalized costs of our oil and gas properties exceeded the present value of our estimated proved reserves by approximately
$3.8 million
,
resulting in the recognition of a proved property impairment of the same amount.
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
September 30, 2017
decreased to
$0.9 million
compared to
$1.0 million
for the same period of 2016. The decrease in interest expense in 2017 was due to lower levels of debt during the three months ended
September 30, 2017
as compared to the same period in 2016.
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 consisted of NYMEX-based fixed price swaps, basis differential swaps and collar contracts as of
September 30, 2017
, and NYMEX-based fixed price swaps and three-way collar contracts as of
September 30, 2016
. The net estimated value of our commodity derivative contracts was a net liability of approximately
$1.0 million
as of
September 30, 2017
. 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
September 30, 2017
, we recognized a loss on our commodity derivative contracts of
$5.5 million
, consisting of a gain on closed contracts of
$1.4 million
and a loss of
$6.9 million
related to open contracts. For the three
months ended
September 30, 2016
, we recognized a gain on our commodity derivative contracts of
$2.4 million
, consisting of a loss of
$1.1 million
on closed contracts and a gain of
$3.5 million
related to open contracts.
Income Tax Expense.
For the three months ended
September 30, 2017
and 2016 there was no income tax expense recognized as a result of NOL carryforwards and a net loss in the three months ended September 30, 2017 and 2016.
Comparison of Nine Months Ended September 30, 2017 to Nine Months Ended September 30, 2016
Operating Revenue
.
During the nine months ended
September 30, 2017
, operating revenue increased to
$56.7 million
from
$34.5 million
for the same period of 2016. The increase in revenue was due to higher prices for all products as well as higher sales volumes for all products. Higher realized commodity prices contributed $15.6 million to revenue, of which $11.2 million was attributable to oil. Higher sales volumes contributed $6.6 million to revenue for the nine months ended September 30, 2017.
Oil sales volumes increased to
1,084
MBbl during the nine months ended
September 30, 2017
from
919
MBbl for the same period of 2016. The increase in oil sales volume was primarily due to new wells brought on line since the third quarter of 2016, offset by natural field declines and property sales. New wells brought on line since the third quarter of 2016 contributed 322 MBbl for the nine months ended
September 30, 2017
. Gas sales volumes increased to
2,754
MMcf for the nine months ended
September 30, 2017
from
2,232
MMcf for the same period of 2016. The increase in gas sales volume was primarily due to new wells brought on line since the third quarter of 2016 which contributed 345 MMcf, which was partially offset by natural field declines and property sales. NGL sales volumes increased to
347
MBbl for the nine months ended
September 30, 2017
from
239
MBbl for the same period of 2016. The increase in NGL sales was primarily due to more gas production in the Rocky Mountain region which has a higher NGL content.
LOE
.
LOE
for the nine months ended
September 30, 2017
decreased to
$11.6 million
from
$13.6 million
for the same period of 2016. The decrease in LOE was primarily due to lower cost of services and less non-recurring LOE in the first nine months of 2017. Additionally, we have focused on lowering LOE and shutting in marginal wells. LOE per Boe for the nine months ended
September 30, 2017
was
$6.16
compared to
$8.89
for the same period of 2016. The decrease per Boe was due to lower service costs and higher production volumes for the nine months ended
September 30, 2017
as compared to the same period of 2016.
Production and Ad Valorem Taxes
. Production and ad valorem taxes for the nine months ended
September 30, 2017
increased to
$4.8 million
from
$3.6 million
for the same period of 2016. The increase was primarily the result of higher commodity prices and sales volumes. Production and ad valorem taxes for the nine months ended
September 30, 2017
were
9%
of total oil, gas and NGL sales compared to
10%
for the same period of 2016. Lower ad valorem taxes contributed to the reduction in the percentage of sales revenue.
G&A Expenses.
G&A expenses, excluding stock-based compensation, increased to
$8.2 million
for the first nine months of 2017 from
$5.8 million
for the same period of 2016. The increase in G&A expense was primarily due to the reinstatement of officers' salaries effective February 1, 2017 and one-time discretionary bonus awards in connection with the closing of transactions in the quarter ended September 30, 2017. G&A expense per Boe, excluding stock-based compensation expense, was
$4.34
for the nine months ended
September 30, 2017
compared to
$3.81
for the same period of 2016. The increase per Boe was primarily due to the higher G&A expense offset by increased sales volumes in the first nine months of 2017 compared to the same period in 2016.
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 nine months ended
September 30, 2017
, stock based compensation expense was
$2.5 million
as compared to
$2.4 million
for the same period of 2016.
DD&A Expenses
. DD&A expense for the nine months ended
September 30, 2017
decreased to
$17.7 million
from
$17.9 million
for same period of 2016. The decrease was primarily due to a reduction in the full cost pool as a result of impairments in 2016 offset by higher sales volumes in the first nine months of 2017 as compared to the same period of 2016. Our DD&A expense per Boe for the nine months ended
September 30, 2017
was
$9.35
compared to
$11.72
for the same period in 2016.
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 net 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
September 30, 2017
, our net capitalized costs of oil and gas properties did not exceed the present value of our estimated proved reserves. As of September 30, 2016, the net capitalized costs of our oil and gas properties exceeded the present value of our estimated proved reserves by approximately
$3.8 million
,
resulting in the recognition of a proved property impairment of the same amount. Total impairment for the nine months ended September 30, 2016 was
$67.6 million
, which included $63.8 million recognized in the first half of 2016.
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 nine months ended
September 30, 2017
was
$1.9 million
as compared to
$3.3 million
for the same period of 2016. The decrease in 2017 was due to lower levels of debt during the nine months ended
September 30, 2017
as compared to the same period of 2016.
(Gain) Loss 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 consisted of NYMEX-based fixed price swaps, basis differential swaps and collar contracts as of
September 30, 2017
, and NYMEX-based fixed price swaps and three-way collar contracts as of September 30, 2016. The net estimated value of our commodity derivative contracts was a net liability of approximately
$1.0 million
as of
September 30, 2017
. When our derivative contract prices are higher than prevailing market prices, we incur realized and unrealized gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur realized and unrealized losses. For the nine months ended
September 30, 2017
, we recognized a gain on our commodity derivative contracts of
$10.4 million
, consisting of a gain on closed contracts of
$3.4 million
on closed contracts and a gain of
$7.0 million
related to our open contracts. For the nine months ended September 30, 2016, we recognized a loss on our commodity derivative contracts of
$10.3 million
, consisting of a gain of
$3.2 million
on our closed contracts and a loss of
$13.5 million
related to our open contracts.
Income Tax Expense.
For the nine months ended
September 30, 2017
and 2016 there was no income tax expense recognized as a result of NOL carryforwards and a net loss in the nine months ended September 30, 2016.
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 2017 including our planned capital expenditures.
Capital Expenditures
. Capital expenditures for the nine months ended
September 30, 2017
and 2016 were
$91.4 million
and
$24.6 million
, respectively.
The table below sets forth the components of these capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2017
|
|
2016
|
|
|
|
(In thousands)
|
Expenditure category:
|
|
|
|
|
|
Exploration/Development
|
|
$
|
90,985
|
|
|
$
|
24,549
|
|
|
Facilities and other
|
|
378
|
|
|
83
|
|
|
Total
|
|
$
|
91,363
|
|
|
$
|
24,632
|
|
|
During the nine months ended
September 30, 2017
and 2016, our expenditures were primarily for development of our existing properties and the acquisition of leaseholds. Expenditures during the nine months ended
September 30, 2017
of
$91.4 million
included non-cash items of
$3.3 million
related to common stock issued for the acquisition of oil and gas properties and
$16.5 million
in capital expenditures that are included in accounts payable as of
September 30, 2017
. We anticipate making capital expenditures in 2017 of approximately $120.0 million. Approximately $71.3 million of the 2017 budget is allocated to developing our Permian/Delaware Basin assets and expanding our acreage position in the Delaware Basin. The 2017 budget also allocates approximately $42.2 million for drilling and completion of wells in our Williston Basin/Bakken/Three Forks play in North Dakota, with the remaining amount allocated to the Eagle Ford in South Texas as well as lease acquisition and general corporate expenses. The 2017 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. 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 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2017
|
|
2016
|
|
|
|
(In thousands)
|
Net cash provided by operating activities
|
|
$
|
22,259
|
|
|
$
|
22,225
|
|
|
Net cash used in investing activities
|
|
(56,216
|
)
|
|
(7,039
|
)
|
|
Net cash provided by (used in) financing activities
|
|
34,776
|
|
|
(18,726
|
)
|
|
Total
|
|
$
|
819
|
|
|
$
|
(3,540
|
)
|
|
Operating activities for the nine months ended
September 30, 2017
provided
$22.3 million
in cash compared to providing
$22.2 million
in the same period of 2016. Non-cash expense items and net changes in operating assets and liabilities accounted for most of these funds. Investing activities used
$56.2 million
during the nine months ended
September 30, 2017
, as expenditures of
$71.5 million
for the development of our existing properties were offset by proceeds from the sale of properties of
$15.3 million
. Investing activities used
$7.0 million
during the nine months ended September 30, 2016, capital expenditures of $24.6 million were offset by proceeds from sales of oil and gas properties of $13.6 million, of which $4.0 million was from the sale of non-oil and gas properties. Financing activities provided
$34.8 million
for the nine months ended
September 30, 2017
compared to using
$18.7 million
for the same period of 2016. Funds provided during the nine months ended
September 30, 2017
were primarily proceeds from the issuance of 28.8 million shares of common stock in January 2017 and borrowings under our credit facility, offset by payments of borrowings under our credit facility. Funds used during the nine months ended September 30, 2016 were primarily payments of our borrowings under our credit facility which were offset by proceeds from borrowings under the credit facility and equity offering in May 2016.
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. In January 2017, we completed an offering of 28.8 million shares of common stock for net proceeds of approximately $65.2 million. Proceeds from the offering were used to reduce amounts outstanding under our credit facility.
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 66% of our total estimated proved reserves on a Boe basis (33% on a PV-10 basis) at December 31, 2016 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:
|
|
•
|
Operating leases for office facilities.
|
Below is a schedule of the future payments that we are obligated to make based on agreements in place as of
September 30, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due in twelve month periods ending:
|
Contractual Obligations
(In thousands)
|
|
Total
|
|
September 30, 2018
|
|
September 30, 2019-2020
|
|
September 30, 2021-2022
|
|
Thereafter
|
Long-term debt (1)
|
|
$
|
67,680
|
|
|
$
|
259
|
|
|
$
|
552
|
|
|
$
|
64,601
|
|
|
$
|
2,268
|
|
Interest on long-term debt (2)
|
|
10,534
|
|
|
2,860
|
|
|
5,686
|
|
|
1,914
|
|
|
74
|
|
Lease obligations (3)
|
|
35
|
|
|
33
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
78,249
|
|
|
$
|
3,152
|
|
|
$
|
6,240
|
|
|
$
|
66,515
|
|
|
$
|
2,342
|
|
___________________________
|
|
(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.
|
|
|
(3)
|
Lease on office space in Dickinson, North Dakota, which expires on October 31, 2018, office space in Lusk, Wyoming, which will expire on December 31, 2017 and office space in Denver, Colorado which will expire on December 31, 2017.
|
We maintain a reserve for costs associated with future site restoration related to the retirement of tangible long-lived assets. At
September 30, 2017
, our reserve for these obligations totaled
$8.8 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
September 30, 2017
, 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
September 30, 2017
, 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:
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017
|
|
December 31, 2016
|
|
|
(In thousands)
|
Credit facility
|
|
$
|
64,000
|
|
|
$
|
93,000
|
|
Rig loan agreement
|
|
—
|
|
|
535
|
|
Real estate lien note
|
|
3,680
|
|
|
3,867
|
|
|
|
67,680
|
|
|
97,402
|
|
Less current maturities
|
|
(259
|
)
|
|
(786
|
)
|
|
|
$
|
67,421
|
|
|
$
|
96,616
|
|
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
September 30, 2017
,
$64.0 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
September 30, 2017
, we had a borrowing base of
$115.0 million
. As of November 6, 2017, in connection with the semi-annual redetermination, the borrowing base was increased to
$135.0 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
September 30, 2017
, the interest rate on the credit facility was approximately
4.23%
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 of 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, 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
September 30, 2017
, we were in compliance with all of these financial covenants. As of
September 30, 2017
, the interest coverage ratio was
20.77
to 1.00, the total debt to EBITDAX ratio was
1.29
to 1.00, and our current ratio was
1.88
to 1.00.
The credit facility contains a number of covenants that, among other things, restrict our ability to:
|
|
•
|
incur or guarantee additional indebtedness;
|
|
|
•
|
transfer or sell assets;
|
|
|
•
|
create liens on assets;
|
|
|
•
|
engage in transactions with affiliates other than on an “arm’s length” basis;
|
|
|
•
|
make any change in the principal nature of our business; and
|
|
|
•
|
permit a change of control.
|
The credit facility also contains certain additional covenants including requirements that:
|
|
•
|
100% of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility; and
|
|
|
•
|
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.
|
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
September 30, 2017
, 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 bears interest at a fixed rate of
4.25%
and is payable in monthly installments of $
34,354
. Beginning August 20, 2018, the interest rate will adjust to the bank's then current prime rate plus
1.00%
with a maximum rate of
7.25%
. The maturity date of the note is July 20, 2023. As of
September 30, 2017
, and December 31, 2016,
$3.7 million
and
$3.9 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 75% of our estimated oil production from our net proved developed producing reserves (based on reserve estimates at September 30, 2017) from October 1, 2017 through December 31, 2017, 75% for 2018 and 48% for 2019. We have also entered into a NYMEX-based collar on approximately 46% of the gas production of our estimated net proved developed producing reserves (based on reserves estimates at September 30, 2017) from October 1, 2017 through December 31, 2017 and a 500 Boepd Midland-Cushing oil price differential swap at ($0.65)/Bbl.
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.