ITEM 1A.
RISK FACTORS
The following risks and uncertainties, together with other information set forth in this Form 10-K, should be carefully considered by current and future investors in our common stock. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties presently unknown to us or currently deemed immaterial also may impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, our financial condition, and the results of our operations, which in turn could negatively impact the value of our common stock.
Oil, natural gas and NGL prices are volatile. A reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.
Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to market uncertainty and relatively minor changes in the supply of and demand for oil, natural gas and NGLs. Historically, oil, natural gas and NGL prices have been volatile. For example, during the period from January 1, 2014 through February 28, 2018, the WTI spot price for oil declined from a high of $107.95 per Bbl on June 20, 2014, to $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas declined from a high of $8.15 per MMBtu on February 10, 2014, to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices. The prices we receive for our oil, natural gas and NGL production heavily influence our revenue, profitability, access to capital, future rate of growth and carrying value of our properties. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:
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worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and NGLs;
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the price and quantity of foreign imports of oil, natural gas and NGLs;
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political and economic conditions in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia;
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actions of the Organization of the Petroleum Exporting Countries, its members and state-controlled oil companies relating to oil price and production controls;
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the level of global exploration, development and production;
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the level of global inventories;
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prevailing prices on local price indexes in the area in which we operate;
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the proximity, capacity, cost and availability of gathering and transportation facilities;
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localized and global supply and demand fundamentals and transportation availability;
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the cost of exploring for, developing, producing and transporting reserves;
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weather conditions and other natural disasters;
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technological advances affecting energy consumption;
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the price and availability of alternative fuels;
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expectations about future commodity prices; and
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U.S. federal, state and local and non-U.S. governmental regulation and taxes.
Lower commodity prices may reduce our cash flows and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves could be adversely affected. Furthermore, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than current West Texas Intermediate or Henry Hub strip prices and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some of our proved undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.
Our acquisition and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue making substantial capital expenditures related to our acquisition and development projects. Our 2018 capital budget for drilling, completion and recompletion activities and facilities costs is expected to range from $560.0 million to $615.0 million, excluding potential acquisitions. In addition, our production costs may increase as we continue to use enhanced recovery techniques and other new drilling and completion technologies, which are capital intensive and may not produce oil and natural gas in paying quantities or at all. Further, we regularly evaluate potential acquisition opportunities as an important aspect of our growth strategy, and any such acquisitions we pursue could require substantial capital expenditures. We expect to fund our capital expenditures with cash on hand, cash generated by operations and borrowings under our credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities would be dilutive to our other stockholders. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.
Our cash flow from operations and access to capital are subject to a number of variables, including:
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the prices at which our production is sold;
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our proved reserves;
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the level of hydrocarbons we are able to produce from existing wells;
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our ability to acquire, locate and produce new reserves;
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results of our hedging program;
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the levels of our operating expenses; and
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our ability to borrow under our credit facility and our ability to access the capital markets.
If our revenues or the borrowing base under our credit facility decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include the following:
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landing our wellbore in the desired drilling zone;
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staying in the desired drilling zone while drilling horizontally through the formation;
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running our casing the entire length of the wellbore; and
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being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that we face while completing our wells include the following:
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the ability to fracture stimulate the planned number of stages;
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the ability to run tools the entire length of the wellbore during completion operations;
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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage; and
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the effectiveness of the fracture stimulation process on reservoir rock.
In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated, we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.
Our decisions to develop or purchase prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “-Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
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delays imposed by or resulting from compliance with regulatory requirements including limitations on wastewater disposal, additional regulation related to seismic activity, discharge of GHGs and limitations on hydraulic fracturing;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining equipment and qualified personnel or in obtaining materials required for our drilling activities, including drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, sand, water and other supplies;
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equipment failures, accidents or other unexpected operational events;
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lack of available and economic gathering and takeaway capacity, including gathering facilities and interconnecting transmission pipelines;
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adverse weather conditions;
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issues related to compliance with environmental regulations;
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environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
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declines in oil and natural gas prices;
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limited availability of financing at acceptable terms;
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title problems; and
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limitations in the market for oil and natural gas.
For example, in 2017 we experienced completion delays related to frac fleet equipment reliability from our service providers, which resulted in increased completed well costs and reduced our total number of well completions. Furthermore, the results of any drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production.
Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.
As of December 31, 2017, we had identified 2,083 gross horizontal drilling locations on our acreage based on approximately 880-foot spacing in an offset pattern with five to six wells across a 640-acre section, consisting of laterals with an average length of 9,094 feet. As a result of the limitations described above, we may be unable to drill many of our identified locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See “-Our acquisition and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.” Any drilling activities we are able to conduct on these locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating reserves is complex. It requires interpretations of available technical data and many assumptions, including current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected and production declines may be greater than we estimate and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves.
It should not be assumed that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on the 12-month average of the first-day-of-the-month pricing, and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we
are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations, including any future borrowings under our credit facility, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on future indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
Our credit agreement contains a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:
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incur additional indebtedness;
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incur liens;
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make investments;
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make loans to others;
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merge or consolidate with another entity;
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sell assets;
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make certain payments;
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enter into transactions with affiliates;
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hedge commodity prices;
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hedge interest rates; and
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engage in certain other transactions without the prior consent of the lenders.
In addition, our credit agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. For example, as described in greater detail in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Credit Facility,” we are required to maintain a ratio of current assets to current liabilities of not less than 1.0 to 1.0, as defined by the Credit Agreement.
Further, under our credit agreement as of December 31, 2017, we were only permitted to hedge up to the greater of 85% of our production from proved reserves and 75% of our reasonably anticipated forecasted production for up to 24 months in the future, and up to the greater of 75% of our production from proved reserves and 50% of our reasonably anticipated production for 25 to 60 months in the future, provided that no hedges may have a term beyond five years.
The restrictions in our credit agreement may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants in our credit agreement impose on us.
A breach of any covenant in our credit agreement would result in a default under the applicable agreement after any applicable cure and grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under
our credit agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
Any significant reduction in our borrowing base under our credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
Our credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually on April 1 and October 1, or during an elected quarterly redetermination. The borrowing base depends on, among other things, projected revenues from, and asset values of, the proved oil and natural gas properties securing our loan. The value of our proved reserves is dependent upon, among other things, the prevailing and expected market prices of the underlying commodities in our estimated reserves. See “-Oil, natural gas and NGL prices are volatile. A reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments” and “-Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” During a borrowing base redetermination, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. Our borrowing base was $425.0 million as of December 31, 2017. The most recent redetermination was completed in March 2018 and resulted in a borrowing base increase to $540.0 million.
In the future, we may not be able to access adequate funding under our credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.
As of December 31, 2017, approximately 52% of our total net acreage was held by production or continuous drilling operations. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions of the leases or the leases are renewed. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.
Our derivative activities may not effectively mitigate the impact of commodity price volatility from our cash flows and could result in financial losses or could reduce our earnings.
We enter into derivative instrument contracts for a portion of our oil production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of any derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
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production is less than the volume covered by the derivative instruments;
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the counterparty to the derivative instrument defaults on its contractual obligations;
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there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
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there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.
Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.
Adverse weather conditions and other natural disasters may negatively affect our operating results and our ability to conduct drilling activities.
Adverse weather conditions and other natural disasters may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, natural gas and NGLs. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations. For example, in 2017 industry infrastructure impacts from Hurricane Harvey caused a portion of our wells to be shut-in for a short period of time, which reduced production and revenue from such wells for that period.
Our operations are substantially dependent on the availability of water, and our ability to dispose of the water we produce. Restrictions on our ability to obtain and dispose water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas development during both the drilling and hydraulic fracturing processes. Drought conditions in Texas have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations or dispose of or recycle water used in operations, or if the prices of water or water disposal increases dramatically, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.
Our producing properties are located in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas, making us vulnerable to risks associated with operating in a single geographic area.
All of our producing properties are geographically concentrated in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas. At December 31, 2017, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs. For example, since our production originates near Midland, Texas, our realizations on sales of our oil production may be affected by the Midland-Cushing price differential, which reflects the difference between the price of crude at Midland, Texas, versus the price of crude at Cushing, Oklahoma, a major hub where oil production from Midland is often transported via pipeline. The price we currently realize on barrels of oil we sell is reduced by the value of the Midland-Cushing differential, which reached as high as $21 per barrel in August 2014. If the Midland-Cushing differential, or other price differentials pursuant to which our production is subject, were to widen due to oversupply or other factors, our revenue could be negatively impacted.
We are dependent on third-party pipeline and trucking systems to transport our production and gathering and processing systems to prepare our production. The lack of available capacity in these systems could interfere with our ability to market the oil and natural gas we produce, and could materially and adversely affect our cash flow and results of operations.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production getting to market. The marketability of our oil and natural gas and production depends in part on the availability, proximity and capacity of gathering, processing, pipeline and trucking systems. The amount of oil and natural gas that can be produced and sold is subject to limitation in certain circumstances, such as a lack of contracted capacity on such systems. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. As a result, we may be required to shut in wells due to the inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. Any significant curtailment in gathering, processing or pipeline system capacity or lack of availability of transport would interfere with our ability to market the oil and natural gas we produce, and could materially and adversely affect the expected results of our drilling program, as well as our cash flow and results of operations.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities experience disruptions, our operations could be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.
We may incur losses as a result of title defects in the properties in which we invest.
The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.
As of December 31, 2017, approximately 54% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves. Further, we may be required to write-down our PUDs if we do not drill those wells within five years after their respective dates of booking.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take write-downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. We may incur noncash impairment charges in the future. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.
We depend upon several significant purchasers for the sale of most of our oil, natural gas and NGL production.
The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. See “Items 1 and 2. Business and Properties-Major Customers.” We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.
Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge, release or emission of materials into the environment, health and safety aspects of our operations or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.
Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements our business, prospects, financial condition or results of operations could be materially adversely affected.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.
Our development activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
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environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;
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abnormally pressured formations;
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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
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fires, explosions and ruptures of pipelines;
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personal injuries and death;
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natural disasters; and
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terrorist attacks targeting oil and natural gas related facilities and infrastructure.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
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injury or loss of life;
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damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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regulatory investigations and penalties;
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suspension of our operations; and
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repair and remediation costs.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:
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unexpected drilling conditions;
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title problems;
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pressure or lost circulation in formations;
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equipment failure or accidents;
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adverse weather conditions;
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compliance with environmental and other governmental or contractual requirements; and
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increases in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we will be able to identify attractive acquisition opportunities. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, our credit agreement imposes certain limitations on our ability to enter into mergers or combination transactions. Our credit agreement also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses or assets.
We may be subject to risks in connection with acquisitions of properties.
The successful acquisition of producing properties requires an assessment of several factors, including:
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recoverable reserves;
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future oil and natural gas prices and their applicable differentials;
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operating costs; and
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potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as-is” basis.
In addition, acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges.
Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.
Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from the drilling of wells.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.
The demand for drilling rigs, pipe and other equipment and supplies (particularly sand and other proppants), as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which industry activity had increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, had increased, as did the costs for those items. To the extent that commodity prices improve in the future, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to resume or increase our development activities could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.
We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.
Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. These costs may rise faster than increases in our revenue if commodity prices rise, or they may rise without a corresponding increase in commodity prices, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the EP Act of 2005, FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Items 1 and 2. Business and Properties-Regulation of the Oil and Natural Gas Industry.”
A change in the jurisdictional characterization of some of the natural gas assets we use by federal, state or local regulatory agencies or a change in policy by those agencies could result in increased regulation of the natural gas assets we use, which could cause our revenues to decline and operating expenses to increase.
Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We believe that the natural gas pipelines we use meet the traditional tests FERC has used to determine if a pipeline is a gathering pipeline and are, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial ongoing litigation and, over time, FERC policy concerning where to draw the line between activities it regulates and activities excluded from its regulation has changed. The classification and regulation of the gathering facilities we use are subject to change based on future determinations by FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels.
Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce, while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
See “Items 1 and 2.-Business and Properties-Regulation of Environmental and Occupational Safety and Health Matters-Regulation of “Greenhouse Gas” Emissions.”
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
See “Items 1 and 2.-Business and Properties-Regulation of Environmental and Occupational Safety and Health Matters-Hydraulic Fracturing Activities.”
Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies recently have focused on a possible connection between the disposal of wastewater in underground injection wells and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity. For example, in 2016, the Texas state legislature provided nearly $5 million to the University of Texas to develop and manage an earthquake monitoring system in Texas. In addition, a number of lawsuits have been filed in other states, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma’s Corporation Commissions Oil and Gas Division is implementing an ongoing response plan that includes reducing the amount of wastewater into certain injection areas. In March 2016, the response plan was updated to target western Oklahoma’s Arbuckle disposal wells. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific
data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well.
We dispose of large volumes of produced water gathered from our drilling and production operations pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel. The termination of employment of senior management or technical personnel could adversely affect operations.
Our future success depends to a large extent on the services of our senior management and key employees. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.
Our variable rate indebtedness subjects us to interest rate risk and increases in interest rates could adversely affect our business.
Borrowings under our credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease.
In addition, our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
The recently enacted U.S. tax reform legislation as well as future U.S. tax legislation could adversely affect our business, results of operations, financial condition and cash flow.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that significantly reforms the Internal Revenue Code of 1986, as
amended. The Tax Act, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The Tax Act is complex and far-reaching and we cannot predict with certainty the resulting impact its enactment has on us. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued and any such changes in interpretations or assumptions could adversely affect our business and financial condition. See Note 8 to our consolidated financial statements included elsewhere in this Annual Report for additional information.
In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of such U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, or local taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition.
Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. As a result, our drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as 3-D seismic, requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.
Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.
Laws regulating the derivatives market could adversely affect our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. Under the Dodd-Frank Act, the CFTC and the SEC have promulgated rules, and are in the process of promulgating other rules, required to implement the derivatives regulatory provisions of the Dodd-Frank Act. Among the rules currently proposed for adoption by the CFTC are proposed rules that would place limits on positions in certain core futures and economically equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. These new position limit rules are not yet final, and the impact of the final position rules on us is uncertain at this time.
The Dodd-Frank Act also made the clearing of swaps over a derivatives clearing organization mandatory and the execution of cleared swaps over a board of trade or swap execution facility mandatory, subject to certain exemptions. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. As of the date hereof, the CFTC has not yet issued notices designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the exception from mandatory clearing available to commercial end-users of swaps, if we were to have to clear any swap we enter, we might not have the same flexibility we have with the bilateral swaps we now
enter and would have to post margin with the derivatives clearing organization for such cleared swaps, which could adversely our ability to execute hedges to reduce risk and protect our cash flow, could adversely affect our liquidity and could reduce cash available to us for capital expenditures.
Certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for exemptions from such margin requirements available to certain users of swaps who are non-financial end-users entering into uncleared swaps to hedge their commercial risks with respect to any swaps we enter for such purpose, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If we do not qualify for an exemption from the margin rules, we could have to post initial and variation margin with the counterparties to our swaps, which could impact our liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect our cash flow.
The full impact of the Dodd-Frank Act’s swap regulatory provisions and the related rules of the CFTC and SEC on our business will not be known until all of the rules to be adopted under the Dodd-Frank Act have been adopted and fully implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act, the existing rules and any new rules could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act’s swap regulatory provisions and the related rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act’s swap regulatory provisions were intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us and our financial condition.
In addition, the European Union and other non-U.S. jurisdictions have implemented or may implement regulations with respect to the derivatives market, some of which impose mechanisms and restrictions similar to those arising under the Dodd-Frank Act and related rules. If we enter into swaps with counterparties based in foreign jurisdictions, we may become subject to such regulations, which could have adverse effects on our operations similar to the possible effects on our operations of the Dodd-Frank Act’s swap regulatory provisions and the rules of the CFTC, SEC and U.S. banking regulators.
We operate in a litigious environment and may be involved in legal proceeding that could have an adverse effect on our results of operations and financial condition.
Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters, and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of our estimated reserves.
Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received.
In addition, our predecessor generally passed through its taxable income to its owners for income tax purposes and was not subject to U.S. federal, state or local income taxes other than franchise tax in the State of Texas. Accordingly, our standardized measure as of December 31, 2016 and 2015 does not provide for U.S. federal, state or local income taxes other
than franchise tax in the State of Texas. However, following our corporate reorganization, we are subject to U.S. federal, state and local income taxes, which is reflected in the standardized measure computation as of December 31, 2017.
Therefore, the standardized measure of our estimated reserves included in this Form 10-K should not be construed as accurate estimates of the current fair value of our proved reserves.
Our business is difficult to evaluate because we have a limited operating history, and we are susceptible to the potential difficulties associated with rapid growth and expansion.
JPE LLC was formed in 2013. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.
In addition, we have grown rapidly over the last several years. Our management believes future success depends on our ability to manage the rapid growth we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:
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increased responsibilities for our executive level personnel;
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increased administrative burden;
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increased capital requirements; and
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increased organizational challenges common to large, expansive operations.
Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.
As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited
to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.
Quantum and its affiliates have the ability to direct the voting of a majority of our common stock, and its interests may conflict with those of our other stockholders.
As of December 31, 2017, Quantum beneficially owned approximately 68.7% of our outstanding common stock. As a result, Quantum is able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of Quantum with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. Given this concentrated ownership, Quantum would have to approve any potential acquisition of us. In addition, certain of our directors are currently employees of Quantum. These directors’ duties as employees of Quantum may conflict with their duties as our directors, and the resolution of these conflicts may not always be in our or your best interest. Furthermore, we are a party to a stockholders’ agreement with Quantum, JPE Management Holdings LLC and certain current and former officers and employees. Among other things, the stockholders’ agreement provides that JPE Management Holdings LLC and the current and former officers and employees party thereto will vote all of their shares of common stock in accordance with the direction of Quantum. Further, the stockholders’ agreement provides Quantum with the right to designate a certain number of nominees to our board of directors so long as it and its affiliates collectively beneficially own at least 5% of the outstanding shares of our common stock.
We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for and rely on exemptions from certain corporate governance requirements. Our stockholders do not have the same protections afforded to stockholders of companies that are subject to such requirements.
Quantum continues to control a majority of the combined voting power of our common stock. As a result, we are a “controlled company” within the meaning of the New York Stock Exchange (“NYSE”) listing standards. Under these rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements of the NYSE, including the requirement (1) that a majority of the board of directors consist of independent directors, (2) that we have a nominating and corporate governance committee composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities and (3) that we have a compensation committee composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities. We rely on some or all of these exemptions. As a result, we do not have a majority of independent directors or a nominating or governance committee, and our compensation committee does not consist entirely of independent directors. Accordingly, our stockholders do not have the same protections afforded to stockholders of companies subject to all of the corporate governance requirements of the NYSE.
Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
Certain of our directors, who are and will be responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including affiliates of Quantum) that are in the business of identifying and acquiring oil and natural gas properties. For example, five of our directors, Messrs. Davidson, Linn,
VanLoh, Jr., Verma and Webster, serve as Venture Partner, Senior Advisor, Founder and Chief Executive Officer, President and Managing Director, respectively, of Quantum Energy Partners, which is in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor.
Quantum and its affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable Quantum to benefit from corporate opportunities that might otherwise be available to us.
Our governing documents provide that Quantum and its affiliates (including portfolio investments of Quantum and its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation will, among other things:
•
permit Quantum and its affiliates and our non-employee directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and
•
provide that if Quantum or any of its affiliates who is also one of our non-employee directors becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.
Quantum or its affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Quantum and its affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to Quantum and its affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours.
Quantum and its affiliates are established participants in the oil and natural gas industry and have resources greater than ours, which may make it more difficult for us to compete with such persons with respect to commercial activities as well as for potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand, and Quantum, on the other hand, will be resolved in our favor. As a result, competition from Quantum and its affiliates could adversely impact our results of operations.
For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.
We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues at the end of any fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates measured as of June 30, or issue more than $1.0 billion of non-convertible debt over a three-year period.
To the extent that we rely on any of the exemptions available to emerging growth companies, stockholders and investors will receive less information about our executive compensation and internal control over financial reporting than issuers that
are not emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition.
Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of these other pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
ITEM 4.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Our common stock began trading on the NYSE under the symbol “JAG” on January 27, 2017. Prior to that, there was no public market for our common stock. The table below sets forth, for the periods indicated, the high and low sales prices per share of our common stock since January 27, 2017.
(1)
For the period from January 27, 2017 through March 31, 2017.
On March 9, 2018, the closing price of our common stock as reported on the NYSE was $12.18 per share. At March 9, 2018, our outstanding shares of 213,126,310 were held by approximately 9 stockholders of record.
Dividends
We have not declared or paid any cash dividends since our inception. Covenants contained in our credit agreement place restrictions on our ability to pay cash dividends. We currently intend to retain future earnings, if any, to finance our operations and the growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
We did not purchase any shares of our common stock during the three months ended December 31, 2017.
Sales of Unregistered Equity Securities
We did not have any sales of unregistered equity securities during the three months ended December 31, 2017.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
The following tables show selected historical consolidated and combined financial data, for the periods and as of the dates indicated. Our historical results are not necessarily indicative of future results. The following selected financial and operating data should be read in conjunction with “Item 7.
Item 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated and combined financial statements and related notes presented in this Annual Report on Form 10-K. The following discussion and analysis contains forward-looking statements, including, without limitation, statements related to our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to update any forward-looking statements except as otherwise required by applicable law.
In this section, references to “Jagged Peak,” “the Company,” “we,” “us” and “our” refer to Jagged Peak Energy Inc. and its subsidiaries, after the initial public offering of Jagged Peak (the “IPO”) and, prior to the IPO, to Jagged Peak Energy LLC (“JPE LLC”).
Jagged Peak Energy Inc. and our Predecessor
Jagged Peak was formed in September 2016 and, prior to the consummation of the IPO, did not have historical financial operating results. For purposes of this Annual Report, our accounting predecessor reflects the results of JPE LLC, which was formed in 2013 to engage in the acquisition, development, exploration and exploitation of oil and natural gas reserves. In connection with the IPO, a corporate reorganization took place whereby JPE LLC became a wholly owned subsidiary of Jagged Peak.
Overview
We are an independent oil and natural gas company focused on the acquisition and development of unconventional oil and associated liquids-rich natural gas reserves. Our operations are entirely located in the United States, within the Permian Basin of West Texas. Our primary area of focus is the southern Delaware Basin; the Delaware Basin is a sub-basin of the Permian Basin. Our acreage is located on large, contiguous blocks in the adjacent Texas counties of Winkler, Ward, Reeves and Pecos, with significant original oil-in-place within multiple stacked hydrocarbon-bearing formations.
We have assembled a portfolio of contiguous acreage in the core oil window of the southern Delaware Basin. This acreage is characterized by a multi-year, oil-weighted inventory of horizontal drilling locations that provide attractive growth and return opportunities. At December 31, 2017, our acreage position was approximately 75,200 net acres. We divide our current areas of operation into three distinct project areas: Cochise, with approximately 12,900 net acres, Whiskey River, with approximately 36,000 net acres, and Big Tex, with approximately 26,300 net acres.
As of December 31, 2017, our estimated proved reserves were approximately 82.4 million MMBoe, consisting of 79% oil. We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operational improvements and cost efficiencies. As the operator of approximately 97% of our acreage, we have the flexibility to manage our development program, which allows us to optimize our field-level returns and profitability.
Market Conditions
Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil, natural gas and NGL production. Compared to 2016, our realized oil price for 2017 increased 18% to $48.56 per barrel, our realized natural gas price increased 9% to $2.52 per Mcf, and our realized price for NGLs increased by 60% to $25.25 per barrel between these same periods. See “Sources of Our Revenues” below for further information regarding our realized commodity prices.
As the U.S. oil and gas industry continues to confront volatile commodity prices, we experience adverse effects on our business, financial condition, results of operations, operating cash flows, liquidity and ability to finance planned capital expenditures. Lower prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore, potentially lower our oil, natural gas and NGL reserves. Decreasing reserves may also reduce the borrowing base under our credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our
proved reserves. Our ability to access capital markets may be restricted, which could have an impact on our flexibility to react to changing economic and business conditions. Further, oversupply and high inventory storage levels could put downward pressure on commodity prices and have an adverse impact on our business partners, customers and lenders, potentially causing them to fail to meet their obligations to us.
Factors Affecting the Comparability of Our Results of Operations
Our historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, primarily for the reasons described below.
Incentive Unit Awards
In conjunction with the closing of the IPO, we recognized equity-based compensation expense for: (1) a charge of $379.0 million related to management incentive units (“MIUs”) in JPE LLC that vested at the time of the IPO; and (2) a charge for the year ended December 31, 2017 of $60.4 million related to shares of common stock transferred to JPE Management Holdings LLC (“Management Holdco”). Please refer to Note 6, Equity-based Compensation, for additional information on equity-based compensation.
Public Company Expenses
Subsequent to our IPO, we incur direct, incremental general and administrative (“G&A”) expenses as a result of being a publicly traded company, including, but not limited to, costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, corporate tax return preparation, increased independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental G&A expenses are not included in our historical results of operations.
Income Taxes
As a result of our corporate reorganization, we became subject to federal and state income tax. The change in tax status required the recognition of deferred tax assets and liabilities for the temporary differences at the time of the change in status. The resulting net deferred tax liability of approximately $80.7 million was recognized as tax expense from continuing operations. For periods following completion of the corporate reorganization, we began recording income taxes associated with our status as a corporation. From the date of the corporate reorganization through December 31, 2017, we recognized $22.8 million of income tax benefit which includes the favorable impact of the Tax Act (as defined below). Please refer to Note 8, Income Taxes, for more information on income taxes.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”), that significantly changes the federal income taxation of business entities. The Tax Act, among other things, reduces the corporate income tax rate from 35% to 21%, partially limits the deductibility of business interest expense and net operating losses, allows the immediate deduction of certain new investments instead of deductions for depreciation expense over time, and eliminates the corporate alternative minimum tax. Due principally to the elimination of the corporate alternative minimum tax and our ability to immediately deduct intangible drilling and completion expenditures, we do not anticipate paying cash income taxes in the near term.
Increased Drilling Activity
Since commencing our drilling program in late 2013, we operated an average of one horizontal drilling rig through June 2016. We began operating our second and third rigs in July of 2016. At December 31, 2017, we were operating six horizontal rigs. During 2017 we completed, or participated in completing, 51 gross (46.1 net) operated wells. Our average daily production has grown from 5,613 Boe/d in 2016 to 16,974 Boe/d in 2017. During 2017 we spent $597.5 million for drilling and completing wells and on water infrastructure costs, which included $1.6 million to purchase surface acreage. This compares to $158.5 million that we spent in 2016 for drilling, completion and infrastructure.
Our board of directors approved a capital budget for 2018 which is projected to range from $560.0 million to $615.0 million, excluding acquisitions. We expect to allocate between $540.0 million and $590.0 million of our 2018 capital budget for the drilling and completion of operated and non-operated wells, and $20.0 million to $25.0 million for water infrastructure costs, excluding any potential additions to surface acreage. At the midpoint, our 2018 capital budget is nearly flat compared to
our 2017 drilling and completion spending of $597.5 million. The ultimate amount of capital that we expend may fluctuate materially based on market conditions, availability and/or attractiveness of acquisitions and our drilling results.
Summary of Operating and Financial Results
•
Successfully completed, or participated in completing, 51 gross (46.1 net) wells, of which we operate 46 gross (44.3 net), all within the southern Delaware Basin;
•
Increased total proved reserves by 118% to 82.4 MMBoe at December 31, 2017, and replaced 821% of 2017 production;
•
Added 51.8 MMBoe of proved reserves from extensions and discoveries;
•
Increased average daily production by 202% to 16,974 Boe/d, comprised of 80% oil;
•
Grew oil production 193% to 13,640 barrels per day, natural gas production by 279% to 9.9 MMcf/d and NGL production rose 219% to 1,690 barrels per day;
•
Production revenues increased 254% to $266.4 million;
•
Increased our borrowing base from $160.0 million to $425.0 million;
•
Improved cash flow from operating activities to $178.9 million from $32.1 million in the previous year;
•
Incurred equity-based compensation expense of $443.0 million, all of which was noncash except for $14.7 million related to an advance made in April 2016;
•
Decreased LOE per Boe from $3.65 in 2016 to $2.88 in 2017;
•
Experienced a noncash derivative loss of $40.0 million;
•
Incurred income tax expense of $57.9 million, which includes deferred taxes recognized upon our corporate reorganization and a reduction of our deferred taxes resulting from the Tax Act; and
•
Incurred a net loss of $451.9 million, largely driven by equity-based compensation charges and income tax expense.
•
Adjusted EBITDAX (non-GAAP) increased by 315% to $203.3 million for the year ended December 31, 2017 (Adjusted EBITDAX is a non-GAAP financial measure. For a definition and discussion of Adjusted EBITDAX and a reconciliation of net income (loss) to Adjusted EBITDAX, see above under “Non-GAAP Financial Measure.”)
Sources of Our Revenues
Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. In 2017, our production revenues were derived 91% from oil sales, 3% from natural gas sales and 6% from NGL sales. Our oil, natural gas and NGL revenues do not include the effects of derivatives.
Increases or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive. Oil, natural gas and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors.
The following table presents our average realized commodity prices, the effects of derivative settlements on our realized prices, and certain major U.S index prices.
While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials for these products.
See “Results of Operations” below for an analysis of the impact changes in realized prices had on our revenues.
In addition to sales of oil, natural gas, and NGLs, we derive a minimal portion of our revenues from third-party sales of fresh water and produced water disposal services. These revenues are reflected as other operating revenues on the consolidated and combined statements of operations.
Production Results
The following table presents production volumes for 2017, 2016 and 2015:
Production Volumes Directly Impact Our Results of Operations
As reservoir pressures decline, production from a given well or formation decreases. Growth in our cash flow, future production and reserves will depend on our ability to continue to add production and proved reserves in excess of our production decline. Accordingly, we plan to maintain our focus on adding reserves through drilling, as well as acquisitions. Our ability to add reserves through drilling projects and acquisitions is dependent on many factors, including our ability to increase our levels of cash flow from operations, borrow or raise capital, obtain regulatory approvals, procure materials, services and personnel and successfully identify and consummate acquisitions.
Operating Costs and Expenses
Costs associated with producing oil, natural gas and NGLs are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production and others are a function of the number of wells we own.
Lease Operating Expenses. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water transportation, injection and disposal, materials and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. Certain operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases.
We monitor our operations to ensure that we are incurring LOE at an acceptable level, including monitoring our LOE on a per Boe basis to determine if any wells or properties should be shut in, repaired, recompleted or sold. This unit rate also allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers. Although we strive to reduce our LOE, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate our properties or make acquisitions and dispositions of properties.
Gathering and Transportation Expenses. Gathering and transportation expenses largely consist of contractual costs to gather, transport and process our natural gas and NGLs. These costs may fluctuate with increases or decreases in production volumes, contractual arrangements and changes in fuel and compression costs.
Production and Ad Valorem Taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold. These taxes are calculated using fixed rates established by the state taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate.
Exploration Expenses. Exploration expenses consist of the costs of unsuccessful exploratory wells and delay rentals for leases on certain unproved properties.
Depletion, Depreciation, Amortization and Accretion. Depletion, depreciation, amortization and accretion (“DD&A”) is primarily the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs incurred related to the acquisition, development, and successful exploration of oil and natural gas properties, and deplete these costs based on the related reserves. DD&A also includes straight-line depreciation of capitalized corporate assets and operations support equipment, as well as the accretion of asset retirement obligation (“ARO”) liabilities.
Impairment of Unproved Oil and Natural Gas Properties. Impairment of unproved oil and natural gas properties represent the cost of unproved properties that will no longer be held by production or extensions of leases.
Other Operating Expenses. Other operating expenses represent water sourcing and disposal costs related to third-party sales, and other costs associated with our oil and natural gas properties.
General and Administrative. G&A consists of costs incurred for overhead, including payroll and benefits for our corporate staff, equity-based compensation, costs of maintaining our headquarters, costs of managing our production and development operations, audit, tax and other fees for professional services and legal compliance.
Interest Expense. We finance a portion of our working capital requirements and capital expenditures with borrowings under our credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under our credit facility in interest expense. Interest expense is reflected net of capitalized interest.
Derivative Activity
Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. As of December 31, 2017, we had entered into derivative oil swap contracts covering periods from January 1, 2018 through December 31, 2019 for approximately 7.6 MMbls of our projected oil production at a weighted average WTI oil price of $52.09 per barrel. We also have basis differential contracts between Midland, TX and Cushing, OK for the periods from January 1, 2018 through December 31, 2019 covering 8.0 MMbls at a weighted average basis differential of $(1.09) per barrel. These derivative instruments allow us to reduce, but not eliminate, the potential variability in cash flow from operations due to fluctuations in oil prices. Our derivative instruments provide increased certainty of cash flows for funding our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil prices and may partially limit our potential gains from future increases in prices. In the future, we may seek to hedge price risk associated with our natural gas and NGL production. See “Item 7A.
ITEM 7A.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLs production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for our oil, natural gas and NGL production depend on numerous factors beyond our control, some of which are discussed in “Item 1A. Risk Factors-Risks Related to Our Business-Oil, natural gas and NGL prices are volatile. A reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.”
Oil sales contributed 91% of our total production revenues for 2017. Natural gas sales contributed 3% and NGL sales contributed 6% of our total production revenues for 2017. Our oil, natural gas and NGL revenues do not include the effects of derivatives instruments used to mitigate price volatility. The following table shows how hypothetical changes in the realized prices we receive for our commodity sales would have impacted revenue for the periods indicated during 2017:
Due to this volatility, we use commodity derivative instruments such as swaps and basis swaps to hedge price risk associated with a portion of our oil production. In the future, we may use commodity derivatives to hedge a portion of our natural gas or NGL production. These hedging instruments will allow us to reduce, but not eliminate, the potential variability in cash flow from operations due to fluctuations in oil prices. This provides increased certainty of cash flows for funding our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil prices and may partially limit our potential gains from future increases in prices. We may seek to hedge price risk associated with our natural gas and NGL production in the future.
Under our Amended and Restated Credit Facility as of December 31, 2017, we are permitted to hedge up to the greater of 85% of our production from proved reserves and 75% of our reasonably anticipated production for up to 24 months in the future, and up to the greater of 75% of our production from proved reserves and 50% of our reasonably anticipated production for 25 to 60 months in the future, provided that no hedges may have a term beyond five years. Under Amendment No. 2 to the Amended and Restated Credit Facility, we are permitted to hedge up to 85% of forecasted production for up to 24 months in the future, and up to the greater of 75% of our production from proved reserves and 60% of our reasonably anticipated forecasted production for 25 to 60 months in the future, provided that no hedges have a term beyond five years.
At December 31, 2017, we had a net liability position of $52.9 million related to our derivatives in place for the years 2018 through 2019. Based on our open derivative positions at December 31, 2017, a 10% increase in the NYMEX WTI price would increase our net oil derivative liability by approximately $43.7 million, while a 10% decrease in the NYMEX WTI price would decrease our net oil derivative liability by approximately $43.7 million.
See Note 3, Derivative Instruments, and Note 4, Fair Value Measurements, to our consolidated and combined financial statements included elsewhere in this report for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts.
Counterparty and Customer Credit Risk
Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as
we deem appropriate. The counterparties to our derivative contracts currently in place have investment grade ratings, and are all lenders or affiliates of lenders under our Amended and Restated Credit Facility.
Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We have little ability to control whether these entities will participate in our wells.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Amended and Restated Credit Facility. At December 31, 2017, we had $155.0 million of debt outstanding, all of which was under Amendment No. 1 to our Amended and Restated Credit Facility, with a weighted average interest rate of 3.68%. At December 31, 2017, borrowings under the Amendment No. to our Amended and Restated Credit Facility bore interest at a rate elected by us that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50%, and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranged from 1.00% to 2.00% in the case of the alternative base rate, and from 2.00% to 3.00% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We paid a commitment fee on unused amounts of our credit facility of 0.375% to 0.50% per year on the unused portion of the borrowing base, depending on the relative amount of the loan outstanding in relation to the borrowing base.
Borrowings under the Amended and Restated Credit Facility following Amendment No. 2 bear interest at a rate we elect that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50%, and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate, and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The commitment fee paid by the Company remains at 0.375% to 0.50% per year on the unused portion of the borrowing base, depending on the relative amount of the loan outstanding in relation to the borrowing base.
Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate would be approximately $1.6 million per year. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this Item is included in this Annual Report as set forth in the “Index to Financial Statements” on page of this report and is incorporated herein by reference.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
In accordance with Rules 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our management, including our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2017. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer
concluded that our disclosure controls and procedures were effective as of December 31, 2017 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the fourth quarter of 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.
As of December 31, 2017, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in "Internal Control - Integrated Framework (2013)", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment and those criteria, management determined that we maintained effective internal control over financial reporting as of December 31, 2017.
Attestation Report of the Registered Public Accounting Firm
This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal controls over financial reporting for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information as to Item 10 is incorporated by reference from the information in our definitive proxy statement for the 2018 Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2017.
Our board of directors has adopted a Code of Business Conduct and Ethics applicable to all officers, directors and employees, which is available on our website (www.jaggedpeakenergy.com) under “Corporate Governance” within the “Investor Relations” section. We will provide a copy of this document to any person, without charge, upon request, by writing to us at Jagged Peak Energy Inc., Investor Relations, 1401 Lawrence Street, Suite 1800, Denver, Colorado 80202. We intend to satisfy the disclosure requirement under Item 406(c) of Regulation S-K regarding an amendment to, or waiver from, a provision of our Code of Business Conduct and Ethics by posting such information on our website at the address and the location specified above.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Information as to Item 11 is incorporated by reference from the information in our definitive proxy statement for the 2018 Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2017.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information as to Item 12 is incorporated by reference from the information in our definitive proxy statement for the 2018 Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2017.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information as to Item 13 is incorporated by reference from the information in our definitive proxy statement for the 2018 Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2017.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Information as to Item 14 is incorporated by reference from the information in our definitive proxy statement for the 2018 Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2017.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
The consolidated and combined financial statements are listed on the Index to Financial Statements to this report beginning on page.
(a)(3) Exhibits.
_______________________________________________________________________________
ITEM 16.
FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
JAGGED PEAK ENERGY INC.
Date:
March 22, 2018
By:
/s/ JOSEPH N. JAGGERS
Name:
Joseph N. Jaggers
Title:
Chairman, Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
Jagged Peak Energy Inc.:
Opinion on the Consolidated and Combined Financial Statements
We have audited the accompanying consolidated and combined balance sheets of Jagged Peak Energy Inc. and subsidiaries (the Company) as of December 31, 2017 and 2016, the related consolidated and combined statements of operations, changes in equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes (collectively, the consolidated and combined financial statements). In our opinion, the consolidated and combined financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These consolidated and combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated and combined financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated and combined financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated and combined financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated and combined financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated and combined financial statements. We believe that our audits provide a reasonable basis for our opinion.
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED BALANCE SHEETS
(in thousands, except share data)
The accompanying Notes are an integral part of these consolidated and combined financial statements.
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
The accompanying Notes are an integral part of these consolidated and combined financial statements.
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY
(in thousands)
The accompanying Notes are an integral part of these consolidated and combined financial statements.
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying Notes are an integral part of these consolidated and combined financial statements.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Note 1-Organization, Operations and Basis of Presentation
Organization and Operations
Jagged Peak Energy Inc. (either individually or together with its subsidiaries, as the context requires, “Jagged Peak” or the “Company”) is an independent oil and natural gas company focused on the acquisition and development of unconventional oil and associated liquids-rich natural gas reserves in the southern Delaware Basin; the Delaware Basin is a sub-basin of the Permian Basin of West Texas. The Company’s acreage is located on large, contiguous blocks in the adjacent counties of Winkler, Ward, Reeves and Pecos, with significant oil-in-place within multiple stacked hydrocarbon-bearing formations.
Corporate Reorganization and Initial Public Offering
Jagged Peak is a Delaware corporation formed in September 2016, as a wholly owned subsidiary of Jagged Peak Energy LLC (“JPE LLC”), a Delaware limited liability company formed in April 2013. JPE LLC was formed by an affiliate of Quantum Energy Partners (“Quantum”) and certain members of Jagged Peak’s management team. Jagged Peak was formed to become the holding company of JPE LLC in connection with Jagged Peak’s initial public offering (the “IPO”).
Immediately prior to the IPO, all capital interests and management incentive units (“MIUs”) in JPE LLC were converted into a single class of units which were then converted into common stock. Certain members of management and employees contributed a portion of common stock received upon the conversion of unvested or unallocated MIUs to JPE Management Holdings LLC, a limited liability company formed in connection with the IPO for the purpose of holding the unvested or unallocated common stock. Also immediately prior to the IPO, a corporate reorganization (the “corporate reorganization”) took place whereby Jagged Peak, initially formed as a subsidiary of JPE LLC, formed JPE Merger Sub LLC as a subsidiary. JPE LLC merged into JPE Merger Sub LLC, with JPE LLC as the surviving entity. As a result, JPE LLC became a wholly owned subsidiary of Jagged Peak. Prior to the corporate reorganization, Quantum owned 98.6% of the membership interests of JPE LLC. Immediately following the corporate reorganization and IPO, Quantum owned 68.7% of the outstanding common stock of Jagged Peak. As all power and authority to control the core functions of Jagged Peak and JPE LLC were, and continue to be, controlled by Quantum, the corporate reorganization was treated as a reorganization of entities under common control and the results of JPE LLC have been consolidated and combined for all periods.
On January 27, 2017, the Company initiated its IPO of common stock to the public, and its common stock began trading on the New York Stock Exchange. During the IPO, the Company and selling stockholders sold 31,599,334 shares at $15.00 per share, raising $474.0 million of gross proceeds. Of the 31,599,334 shares issued to the public, 28,333,334 shares were sold by the Company, and 3,266,000 shares were sold by the selling stockholders. The gross proceeds of the IPO to the Company, based on the public offering price of $15.00 per share, were approximately $425.0 million, which resulted in net proceeds to the Company of $397.0 million after deducting expenses and underwriting discounts and commissions of approximately $28.0 million. The Company did not receive any proceeds from the sale of the shares by the selling stockholders. A portion of the proceeds from the IPO were used to repay the entire outstanding balance on JPE LLC’s credit facility of $142.0 million as of the date the IPO proceeds were received. The remainder of the net proceeds from the IPO were used to fund a portion of the Company’s 2017 capital expenditures program, and for other general corporate purposes.
Basis of Presentation
The accompanying consolidated and combined financial statements include the accounts of Jagged Peak and JPE LLC, and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). These consolidated and combined financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany and intra-company amounts have been eliminated. The consolidated and combined financial statements for periods prior to January 27, 2017 reflect the historical results of JPE LLC, other than the equity-based compensation expense and deferred tax expense, as further described in Notes 6 and 8, respectively.
Certain reclassifications have been made to prior period amounts to conform to the current presentation.
Industry Segment and Geographic Information
The Company evaluated how it is organized and managed, and has identified one operating segment-the production and development of oil and natural gas. All of the Company’s assets are located in the United States, and all of its revenues are
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
attributable to customers located in the United States.
Note 2-Significant Accounting Policies and Related Matters
Use of Estimates
In the course of preparing the consolidated and combined financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Estimates made in preparing these consolidated and combined financial statements include, among other things, (1) estimates of oil and natural gas reserve quantities, which impact depreciation, depletion and amortization and impairment of oil and natural gas properties, (2) operating and capital costs accrued, (3) estimates of timing and costs used in calculating asset retirement obligations, (4) estimates of the fair value of equity-based compensation, (5) estimates used in developing fair value assumptions and estimates, (6) estimates of deferred income taxes and (7) estimates and assumptions used in the disclosure of commitments and contingencies. Changes in estimates, assumptions or actual results could have a significant impact on results in future periods.
Fair Value Measurements
The Company’s financial instruments are measured at estimated fair value, and consist of derivative instruments, cash and cash equivalents, accounts payable and accrued expenses. The Company’s derivative instruments are measured at fair value on a recurring basis. The carrying amounts of the Company’s other financial instruments are considered to be representative of their fair market value due to their short-term nature.
The Company also applies fair value accounting guidance to measure nonfinancial assets and liabilities, such as the acquisition or impairment of oil and gas properties and the inception value of asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. See Note 4, Fair Value Measurements, for further discussion.
Cash and Cash Equivalents
The Company considers all liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company’s cash balances held at commercial banks may at times exceed the Federal Deposit Insurance Corporation limit. The Company has not experienced any credit losses to date.
Revenue Recognition
Revenue is recognized when production is delivered to a purchaser at a fixed and/or determinable price, title has transferred and the collectability of the revenue is probable. Oil, natural gas and NGL revenue is recorded using the sales method. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. As of December 31, 2017 and 2016, the Company had no assets or liabilities recorded for oil, natural gas or NGL imbalances.
Accounts Receivable
The Company’s accounts receivable are generated primarily from the sale of oil, natural gas and NGLs to various customers, from the billing of working interest partners for work on wells the Company operates, and from derivative settlements receivable shortly after the balance sheet date. The Company monitors the financial strength of its customers, partners, and counterparties. At December 31, 2017 and 2016, the Company did not have any reserves for doubtful accounts and did not incur any bad debt expense in any period presented.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
At December 31, 2017 and 2016, accounts receivable was comprised of the following:
Significant Customers
The Company’s share of oil, natural gas and NGL production is sold to a relatively small number of customers. The loss of any single purchaser could materially and adversely affect the Company’s revenues in the short-term; however, the Company believes that the loss of any of its purchasers would not have a long-term material adverse effect on its financial condition and results of operations as oil and natural gas are fungible products with well-established markets and numerous purchasers.
The following purchasers individually accounted for 10% or more of the Company’s total production revenue during the years ended December 31, 2017, 2016 and 2015:
Other Current Assets
The components of other current assets are shown below:
Incremental costs directly related to the IPO were capitalized as deferred offering costs within other current assets until the IPO, at which point these costs were offset against the proceeds received.
Derivative Instruments
The Company uses commodity derivative instruments to manage its exposure to oil and natural gas price volatility. All of the commodity derivative instruments are utilized to manage price risk attributable to the Company’s expected oil and natural gas production, and the Company does not enter into such instruments for speculative trading purposes. The Company does not designate any derivative instruments as hedges for accounting purposes. The Company records all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. The Company records gains and losses from the change in fair value of derivative instruments in current earnings as they occur. The Company currently does not utilize any derivative instruments to manage exposure to variable interest rates, but may do so in the future.
The cash flow impact of the Company’s derivative activities is reflected as cash flows from operating activities. See Note 3, Derivative Instruments, for a more detailed discussion of the Company’s derivative activities.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Oil and Natural Gas Properties
A summary of the Company’s oil and natural gas properties, net is as follows:
Proved Oil and Natural Gas Properties
The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Under this method, all costs incurred related to the acquisition of oil and natural gas properties and the costs of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed when the well is determined not to have recoverable reserves in commercial quantities. Other items charged to expense generally include lease and well operating costs and delay rentals. Geological and geophysical costs directly related to developing proved properties are capitalized. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units of production amortization rate.
Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. Capitalized well costs, including asset retirement costs, are depleted based on proved developed reserves on a field basis. For the years ended December 31, 2017, 2016 and 2015, the Company recorded depletion for oil and natural gas properties of $109.2 million, $39.4 million and $22.2 million, respectively. Depletion expense is included in depletion, depreciation, amortization and accretion expense on the accompanying consolidated and combined statements of operations.
Proved oil and natural gas properties are reviewed for impairment when facts and circumstances indicate their carrying value may not be recoverable. The Company estimates the expected future cash flows of oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to estimated fair value. The factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs, as further discussed in Note 4, Fair Value Measurements. The Company did not record any impairment expenses associated with its proved properties during the years ended December 31, 2017, 2016 and 2015.
Unproved Oil and Natural Gas Properties
Unproved oil and natural gas properties consist of costs to acquire undeveloped leases and unproved reserves, and are capitalized when incurred. When a successful well is drilled on an undeveloped leasehold or reserves are otherwise attributed to a property, unproved property costs are transferred to proved properties. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered.
Unproved properties are periodically assessed for impairment on a property-by-property basis. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage, and records impairment expense for any decline in value. Impairment of unproved properties for leases which have expired, or are expected to expire, was $0.4 million, $0.4 million and $6.5 million for the years ended December 31, 2017, 2016 and 2015, respectively. Additionally, during 2016 the Company incurred dry hole costs of $1.2 million related to a vertical test well drilled to an unproductive shallow horizon. There were no dry hole costs incurred in 2017 or 2015. Impairments are presented within impairment of unproved oil and natural gas properties, while dry hole costs are presented within exploration expenses on the consolidated and combined statements of operations.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Oil and Natural Gas Reserves
The estimates of proved oil and natural gas reserves utilized in the preparation of the financial statements are estimated in accordance with the rules established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”). The Company’s annual reserve estimates were prepared by third-party petroleum engineers. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash flows, future gross revenue, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. See “Supplemental Oil and Natural Gas Disclosures (Unaudited)” following these Notes for a more detailed discussion of the Company’s oil and natural gas reserves.
Other Property and Equipment
The following table presents the components of other property and equipment, net:
Other property and equipment includes equipment used in drilling and completion activities, the Company’s field office, leasehold improvements, vehicles, IT hardware and software and office furniture, and is recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives, which range from 2 to 20 years. Depreciation expense for the years ended December 31, 2017, 2016 and 2015 was $1.7 million, $0.9 million and $0.4 million, respectively. When property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounting records.
Unamortized Debt Issuance Costs
The Company incurred legal and bank fees in connection with obtaining its senior secured revolving credit facility and incurs such fees when increasing bank commitments in conjunction with redetermining an increase in its borrowing base. These costs are stated on the consolidated and combined balance sheets as noncurrent assets at cost, net of amortization, which is computed over the life of the credit facility using the straight-line method and recognized as interest expense on the consolidated and combined statements of operations.
Other Noncurrent Assets
At December 31, 2017, other noncurrent assets primarily consists of deposits for office space leases. At December 31, 2016, other noncurrent assets included a $14.7 million cash advance to management incentive unit advance recipients. The advance was recognized on the consolidated and combined statements of operations as equity-based compensation expense upon the IPO, which was considered a vesting event. See Note 6, Equity-based Compensation, for more information on the management incentive unit advance.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Accrued Liabilities
The components of accrued liabilities are shown below:
Asset Retirement Obligations
The Company records a liability for the fair value of an asset retirement obligation (“ARO”) related to future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and restoration in accordance with local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized in proved oil and natural gas property costs as part of the carrying cost of the oil and natural gas asset, and depleted over the life of the asset. The recognition of the ARO requires management to make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements, credit-adjusted risk-free discount rates and inflation rates. Revisions to estimated ARO can result from changes in working interest, retirement cost estimates and estimated timing of abandonment. The ARO liability is accreted at the end of each period through charges to accretion expense, which is included in the statements of operations within depletion, depreciation, amortization and accretion expense.
Equity-based Compensation
The Company recognizes compensation cost related to equity-based awards granted to employees, members of the Company’s board of directors and non-employee contractors in the financial statements based on their estimated grant-date fair value. The Company may grant various types of equity-based awards including stock options, stock appreciation rights, restricted stock, restricted stock units (including awards with service-based vesting and market condition-based vesting provisions), stock awards, dividend equivalents and other types of awards. Service-based restricted stock and units are valued using the market price of Jagged Peak’s common stock on the grant date. The fair value of the market condition-based restricted stock units is based on the grant-date fair value of the award utilizing a Monte Carlo valuation model. Compensation cost is recognized ratably over the applicable vesting period, and is recognized in general and administrative expense on the consolidated and combined statements of operations. The Company has elected to account for forfeitures in compensation expense as they occur. Equity-based compensation arrangements to nonemployees are recognized as expense over the related service period and are subject to remeasurement at the end of each reporting period until they vest.
Income Taxes
Income taxes are accounted for under the asset and liability method. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses, interest expense and tax credit carryforwards, using enacted tax rates in effect for the taxing jurisdiction in which the Company operates for the year in which those temporary differences are expected to be recovered or settled. Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The Company classifies all deferred tax assets and liabilities as noncurrent. The Company recognizes the financial statement effects of a tax position when it is more likely than not, based on technical merits, that the position will be sustained upon examination. The Company periodically assesses the realizability of its deferred tax assets by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available positive and negative evidence when determining whether a valuation allowance is required. In making this assessment, the Company evaluates possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences available and tax planning strategies. Deferred tax assets are then reduced by a valuation allowance if the Company believes it is more likely than not such deferred tax assets will not be realized.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
The Company’s accounting predecessor, JPE LLC, was treated as a partnership for federal and state income tax purposes. Accordingly, the accompanying consolidated and combined financial statements do not include a provision or liability for income taxes prior to the corporate reorganization.
Earnings per Share
The Company uses the treasury stock method to determine the potential dilutive effect of restricted stock units and performance stock units.
Defined Contribution Plan
The Company sponsors a 401(k) defined contribution plan for the benefit of all employees at their date of hire. The plan allows eligible employees to contribute a portion of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions for participating employees up to a certain percentage of the employee contributions. Matching contributions totaled approximately $0.5 million in the year ended December 31, 2017, and $0.2 million for each of the years ended December 31, 2016 and 2015. Benefits under this plan are available to all employees, and employees are fully vested in the employer contribution upon receipt.
Recent Accounting Pronouncements
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new guidance requires companies to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-11, which rescinds the SEC accounting guidance regarding the use of the entitlements method for recognition of natural gas revenues. The standards can be adopted using either a full retrospective method or a modified retrospective method, as outlined in ASU 2014-09. The new standards became effective for the Company on January 1, 2018, and the Company has elected to adopt it using the modified retrospective method. The Company evaluated its existing contracts and determined it will not be required to record a cumulative effect adjustment as the new standards did not have a material impact compared to the Company’s current use of the sales method, which is generally consistent with the new standards. The Company implemented the necessary changes to its business processes, systems and controls to support recognition and disclosure of this new standard. While the Company does not expect 2018 net income (loss) or cash flows from operations to be impacted by revenue recognition timing changes, there will be certain changes to the presentation of revenues and related expenses beginning January 1, 2018. If the new standard had been in effect for previous periods, all gathering and transportation expenses would have been included as a reduction to natural gas and NGL sales.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires all leases with a term greater than one year to be recognized on the balance sheet as right-of-use assets and lease liabilities. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and cash flows. The Company will adopt the new standard on January 1, 2019, using the modified retrospective approach. The Company is in process of evaluating the impact of this new standard, which includes an analysis of existing contracts, including drilling rig and frac fleet contracts, office leases and certain field equipment. The Company is also evaluating the effect of ASU 2016-02 on its current accounting policies and disclosures. The Company believes that adopting the standard will result in increases to the assets and liabilities on its consolidated and combined balance sheets, and changes to the timing and presentation of certain operating expenses on its consolidated and combined statements of operations. The update does not apply to leases of mineral rights to explore for or use oil and natural gas. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Company's adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. The Company intends to elect this transition provision. The Company continues to monitor relevant industry guidance regarding the implementation of ASU 2016-02 and will adjust its implementation strategies as necessary.
In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) Scope of Modification Accounting. The ASU clarifies which changes to the terms or conditions of an equity-based payment award require an entity to
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Notes to Consolidated and Combined Financial Statements
apply modification accounting in Topic 718. The standard became effective for the Company on January 1, 2018. The impact of this new standard will depend on the extent and nature of future changes to the terms of Company's equity-based payment awards.
Note 3-Derivative Instruments
The Company hedges a portion of its crude oil sales through derivative instruments to mitigate volatility in commodity prices. The use of these instruments exposes the Company to market basis differential risk if the WTI price does not move in parity with the Company’s underlying sales of crude oil produced in the southern Delaware Basin. The Company also hedges a portion of its market basis differential risk through basis swap contracts.
The Company’s derivative instruments are carried at fair value on the consolidated and combined balance sheets. The Company estimates the fair value using risk adjusted discounted cash flow calculations. Cash flows are based on published future commodity price curves for the underlying commodity as of the date of the estimate. Due to the volatility of commodity prices, the estimated fair values of the Company’s derivative instruments are subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. For more information, refer to Note 4, Fair Value Measurements.
Commodity Price Risk
The Company’s principal market risks are its exposure to changes in oil, natural gas and NGL commodity prices. The prices of these commodities are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond the Company’s control. The Company monitors these risks and enters into commodity derivative transactions designed to mitigate the impact of commodity price fluctuations on its business.
In an effort to reduce the variability of the Company’s cash flows, the Company hedged the commodity prices associated with a portion of its expected future oil volumes by entering into swap and basis swap derivative financial instruments. With swaps, the Company typically receives an agreed upon fixed price for a specified notional quantity of oil or natural gas, and the Company pays the hedge counterparty a floating price for that same quantity based upon published index prices. Basis swap contracts establish the differential between Cushing WTI prices and Midland WTI prices, and represent the amount of reduction to Cushing, Oklahoma, prices for the notional volumes contracted. The Company’s commodity derivatives may expose it to the risk of financial loss in certain circumstances. The Company’s derivative arrangements provide protection on the hedged volumes if market prices decline below the prices at which these derivatives are set. If market prices rise above the prices at which the Company has hedged, the Company will be required to make settlement payments to its derivative counterparties.
The following table summarizes the Company’s derivative contracts as of December 31, 2017:
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Notes to Consolidated and Combined Financial Statements
(1)
The index prices for the oil swaps are based on the NYMEX-WTI monthly average futures price.
(2)
The oil basis swap differential price is between Cushing-WTI and Midland-WTI.
The Company has elected to not apply hedge accounting, and as a result, its earnings are affected by the use of the mark-to-market method of accounting for derivative financial instruments. The changes in fair value of these instruments are recognized through earnings as other income or expense rather than deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause noncash earnings volatility due to changes in the underlying commodity price indices. The ultimate gain or loss upon settlement of these transactions is recognized in earnings as other income or expense. Cash settlements of the Company’s derivative contracts are included in cash flows from operating activities in the Company’s statements of cash flows.
Subsequent to December 31, 2017, the Company entered into the following additional derivative contracts:
(1)
The index prices for the oil swaps are based on the NYMEX-WTI monthly average futures price.
(2)
The oil basis swap differential price is between Cushing-WTI and Midland-WTI.
The Company recognized the following gains (losses) and net cash receipts (payments) in earnings for the years ended December 31, 2017, 2016 and 2015:
The Company’s derivative contracts are carried at their fair value on the Company’s consolidated and combined balance sheets using Level 2 inputs, and are subject to industry standard master netting arrangements, which allow the Company to offset recognized asset and liability fair value amounts on contracts with the same counterparty. The Company’s policy is to not offset these positions in its consolidated and combined balance sheets.
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Notes to Consolidated and Combined Financial Statements
The following tables present the amounts and classifications of the Company’s commodity contract derivative assets and liabilities as of December 31, 2017 and 2016 (in thousands):
Derivative Counterparty Risk
Where the Company is exposed to credit risk in its financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement and monitors the appropriateness of these counterparties on an ongoing basis. Generally, the Company does not require collateral and does not anticipate nonperformance by its counterparties.
The Company’s counterparty credit exposure related to commodity derivative instruments is represented by contracts with a net positive fair value at the reporting date. These outstanding instruments, if any, expose the Company to credit risk in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of the Company’s counterparties decline, its ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third-party. In the event of a counterparty default, the Company may sustain a loss and its cash receipts could be negatively impacted.
At December 31, 2017, the Company had commodity derivative contracts with three counterparties, all of which were lenders or affiliates of lenders under the Company’s Amended and Restated Credit Facility (as defined in Note 5, Debt Obligations) and all of which had investment grade credit ratings. These counterparties accounted for all the Company’s counterparty credit exposure related to commodity derivative assets.
Note 4-Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Financial assets and liabilities are measured at fair value on a recurring basis. Nonfinancial assets and liabilities, such as the initial measurement of ARO liabilities and oil and natural gas properties upon acquisition or impairment, are recognized at fair value on a nonrecurring basis.
The Company categorizes the inputs to the fair value of its financial assets and liabilities using a three-tier fair value hierarchy, established by the FASB, that prioritizes the significant inputs used in measuring fair value:
Level 1-Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing
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Notes to Consolidated and Combined Financial Statements
information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and U.S. government treasury securities.
Level 2-Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry standard models that consider various assumptions, including quoted prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in the category include nonexchange-traded derivatives such as over-the-counter forwards, swaps and options.
Level 3-Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value, and the company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
Assets and liabilities measured on a recurring basis
Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. To determine the fair value at the end of each reporting period, the Company computes discounted cash flows for the duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward commodity price curves as of the date of the estimate. The Company compares these prices to the price parameters contained in its hedge contracts to determine estimated future cash inflows or outflows, which are then discounted. The fair values of the Company’s commodity derivative assets and liabilities include a measure of credit risk. These valuations are Level 2 inputs.
The following table is a listing of the Company’s assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2017 and 2016:
Assets and liabilities measured on a nonrecurring basis
The Company applies the provisions of the fair value measurement standard on a nonrecurring basis to its nonfinancial assets and liabilities, such as the acquisition or impairment of proved and unproved oil and gas properties and the inception value of ARO liabilities. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations.
The Company reviews its proved oil and natural gas properties for impairment whenever facts and circumstances indicate their carrying value may not be recoverable. In such circumstances, the income approach is used to determine the fair value of proved oil and natural gas reserves. Under this approach, the Company estimates the expected future cash flows of oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to estimated fair value. The factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs. No impairments were recorded on proved properties during the years ended December 31, 2017, 2016 and 2015.
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Notes to Consolidated and Combined Financial Statements
Unproved oil and natural gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of the unproved properties, the Company uses a market approach, and takes into account future development plans, remaining lease term, drilling results, and reservoir performance. The Company recorded impairment expense on unproved oil and gas properties of $0.4 million, $0.4 million and $6.5 million for the years ended December 31, 2017, 2016 and 2015, respectively. These impairments resulted from expirations of certain undeveloped leases.
The inception value and revision value, if any, of the Company’s AROs are also measured at fair value on a nonrecurring basis. The inputs used to determine such fair value are based primarily on the present value of estimated future cash outflows. Given the unobservable nature of these inputs, they represent Level 3 inputs.
The fair value measurements of assets acquired and liabilities assumed in a business acquisition are measured on a nonrecurring basis on the acquisition date using an income valuation approach based on inputs that are unobservable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.
Fair Value of Other Financial Instruments
The Company has other financial instruments consisting primarily of cash and cash equivalents, accounts receivable, other current assets, accounts payable, and accrued liabilities that approximate fair value due to the nature of the instrument and the short-term maturities of these instruments.
Note 5-Debt Obligations
In June 2015, JPE LLC entered into a five-year senior secured revolving credit facility (“JPE LLC’s Credit Facility”), with a maximum facility amount of $500.0 million. At December 31, 2016, JPE LLC’s Credit Facility, as amended, had a borrowing base of $160.0 million, with $132.0 million outstanding under the credit facility, and $28.0 million in unused borrowing capacity. The weighted-average interest rate as of December 31, 2016 was 3.99%. During the year ended December 31, 2016, JPE LLC capitalized $0.1 million of interest. Following the IPO, the outstanding balance under JPE LLC’s Credit Facility was paid in full.
In January 2017, JPE LLC’s Credit Facility borrowing base was increased to $180.0 million.
In February 2017, the Company, as parent guarantor, and JPE LLC, as borrower, entered into an amended and restated credit facility with Wells Fargo Bank, N.A., as administrative agent and the lenders thereto (the “Amended and Restated Credit Facility”). The borrowing base remained at $180.0 million, while the maximum facility amount increased to $1.0 billion. Borrowings under the Amended and Restated Credit Facility bore interest at a rate elected by the Company that was equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50%, and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranged from 1.25% to 2.25% in the case of the alternative base rate and from 2.25% to 3.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company paid a commitment fee of 0.50% per year on the unused portion of the borrowing base.
The Amended and Restated Credit Facility matures on February 1, 2022, and is subject to semiannual borrowing base redeterminations on or around April 1 and October 1 of each year. The borrowing base increased from $180.0 million to $250.0 million after the April 2017 redetermination.
In October 2017, the Company and JPE LLC entered into an amendment to the Amended and Restated Credit Facility (“Amendment No. 1”). Under Amendment No. 1, the borrowing base increased to $425.0 million and the pricing grid was lowered. Following Amendment No. 1, the Amended and Restated Credit Facility remains subject to semiannual borrowing base redeterminations on or around April 1 and October 1 of each year. Borrowings under the Amended and Restated Credit Facility following Amendment No. 1 bore interest at a rate elected by the Company that was equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50%, and the thirty-day adjusted LIBOR
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Notes to Consolidated and Combined Financial Statements
plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranged from 1.00% to 2.00% in the case of the alternative base rate, and from 2.00% to 3.00% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company paid a commitment fee of 0.375% to 0.50% per year on the unused portion of the borrowing base, depending on the relative amount of the loan outstanding in relation to the borrowing base.
Amendment No. 1 is secured by oil and natural gas properties representing at least 90% of the value of the Company’s proved reserves. Amendment No. 1 contains certain covenants, including among others, restrictions on indebtedness, restrictions on liens, restrictions on investments, restrictions on mergers, restrictions on sales of assets, restrictions on dividends and payments to the Company’s capital interest holders and restrictions on the Company’s hedging activity.
Amendment No. 1 contains financial covenants, which are measured on a quarterly basis. The covenants, as defined in the Amended and Restated Credit Agreement, include requirements to comply with the following financial ratios:
•
a current ratio, which is the ratio of consolidated current assets (including unused commitments under the credit facility and excluding noncash assets related to ARO and derivatives) to consolidated current liabilities (excluding the current portion of long-term debt under the credit agreement and noncash liabilities related to ARO and derivatives), as of the last day of each fiscal quarter, of not less than 1.0 to 1.0; and
•
a leverage ratio, which is the ratio of consolidated Debt (as defined in the credit agreement) as of the last day of each fiscal quarter, subject to certain exclusions (as described in the credit agreement) to EBITDAX (as defined in the credit agreement) for the last 12 months ending on the last day of that fiscal quarter, of not greater than 4.0 to 1.0.
As of December 31, 2017, the Company was in compliance with its financial covenants.
As of December 31, 2017, there was $155.0 million outstanding under Amendment No. 1 of the Amended and Restated Credit Facility. The weighted-average interest rate as of December 31, 2017 was 3.68%. During the year ended December 31, 2017, the Company capitalized $0.3 million of interest.
In March 2018, the Company entered into Amendment No. 2 to the Amended and Restated Credit Facility which extended the maturity date of the Amended and Restated Credit Facility to March 2023, increased the maximum facility amount to $1.5 billion, increased the borrowing base to $540.0 million, increased the hedging limits and lowered the pricing grid. Borrowings under the Amended and Restated Credit Facility following Amendment No. 2 bear interest at a rate elected by the Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50%, and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate, and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The commitment fee paid by the Company remains at 0.375% to 0.50% per year on the unused portion of the borrowing base, depending on the relative amount of the loan outstanding in relation to the borrowing base.
Note 6-Equity-based Compensation
In connection with the IPO, the Company adopted the Jagged Peak Energy Inc. 2017 Long Term Incentive Plan (the “Plan”), which allows the Company to grant up to 21,200,000 equity-based compensation shares to employees, consultants and directors of the Company and its affiliates who perform services for the Company. The Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, performance awards and other types of awards. The terms and conditions of the awards granted are established by the Company’s Board of Directors. Shares issued as a result of awards granted under the Plan are generally new common shares.
Equity-based compensation expense, which is recorded in general and administrative expense in the accompanying consolidated and combined statements of operations, was as follows for the periods indicated:
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Notes to Consolidated and Combined Financial Statements
Incentive Unit Awards
In connection with its formation in April 2013, JPE LLC established an incentive pool plan, whereby JPE LLC granted MIUs to employees and selected other participants. The MIUs were considered “profits interests” that participated in certain events whereupon distributions would be made to MIU holders (only after certain return thresholds were achieved by the capital interests) following a qualifying initial public offering, sale, merger, or other qualifying transaction involving the units or assets of JPE LLC (“Vesting Event”).
The MIUs were accounted for under FASB ASC Topic 710, Compensation-General, which requires compensation expense for the MIUs to be recognized when all performance, market and service conditions are probable of being satisfied, which is generally upon a Vesting Event. As of and through December 31, 2016, the vesting of the MIUs was not deemed probable, therefore no expense was recognized through December 31, 2016.
The corporate reorganization provided a mechanism by which all capital interests and MIUs in JPE LLC were converted into a single class of units, which were then converted into the Company’s common stock. A portion of these shares vested and a portion were transferred to JPE Management Holdings LLC (“Management Holdco”) and became subject to the terms and conditions of the amended and restated JPE Management Holdings LLC limited liability company agreement (the “Management Holdco LLC Agreement”). As a result of the IPO, the satisfaction of all conditions relating to MIUs in JPE LLC held by the current and former officers and employees who owned equity interests in JPE LLC, was deemed probable. As a result, based on the Company’s IPO price of $15.00 per share, compensation expense of $379.0 million was recognized for the vested shares of common stock at the IPO date, all of which was noncash except for $14.7 million related to a management incentive advance payment made in April 2016. The $14.7 million is included in the consolidated and combined statements of cash flows as an operating activity for the year ended 2016.
The shares of common stock transferred to Management Holdco are accounted for under ASC 718, Compensation-Stock Compensation, and generally vest over three years. During the year ended December 31, 2017, the Company recognized $60.4 million of equity-based compensation expense related to the shares held by Management Holdco. Included in the $60.4 million is $22.2 million of equity-based compensation related to awards held by Management Holdco which were modified in conjunction with a March 2017 separation agreement of a former executive officer. The remaining compensation expense of these awards will be recognized ratably according to the terms of the Management Holdco LLC Agreement. The equity-based compensation relative to these shares of common stock transferred to Management Holdco is not deductible for federal or state income tax purposes.
A summary of incentive unit award activity for the year ended December 31, 2017 is as follows:
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Notes to Consolidated and Combined Financial Statements
The total fair value of incentive units that vested from the IPO date to December 31, 2017 was $25.2 million.
At December 31, 2017, there were 431,321 of unallocated shares of Company common stock held at Management Holdco. When these shares are granted, they will be valued using the closing stock price on the date of grant, and the Company will recognize the related expense over the requisite service period.
In February 2018, certain employees notified the Company of their desire to terminate their employment. Under the terms of the Management Holdco LLC Agreement, upon voluntary termination of employment by an incentive unit award holder, the Board of Directors has the discretion to allow outstanding unvested incentive unit awards to immediately vest, to continue to vest post-termination, and/or to be automatically forfeited, or any combination thereof. Any forfeited incentive units are reallocated to the remaining incentive unit holders employed by the Company. In February 2018, the Board of Directors modified these employees’ unvested incentive units to either immediately accelerate vesting, in the case of retiring employees, or continue to vest post-termination under the original vesting period. The Company determined that these are accounted for as modifications under ASC 718 in the first quarter of 2018. As a result of these modifications to the service requirements, the Company determined that, for accounting purposes under ASC 718, the incentive unit awards allocated at IPO no longer met the substantive service condition, and that any previously unrecognized equity-based compensation expense should be recognized immediately. The acceleration of all previously unrecognized equity-based compensation expense for incentive unit awards allocated at the time of the IPO will result in the recognition of approximately $71.2 million of noncash equity-based compensation expense in the first quarter of 2018. This accounting does not alter the legal service obligations under the Management Holdco LLC Agreement for remaining employees whose awards were not modified. Equity-based compensation expense recognition related to incentive unit awards that were unallocated at the time of the IPO is unaffected.
Restricted Stock Unit Awards
Restricted stock unit awards (“RSUs”) vest subject to the satisfaction of service requirements. Expense related to each RSU award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur through reversal of expense on awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant.
A summary of RSU award activity for the year ended December 31, 2017 is as follows:
Of the 588,894 RSUs granted during 2017, nonemployee directors received 55,744 at a weighted average grant-date fair value of $12.46. The remaining compensation costs at December 31, 2017 for these nonemployee director RSUs was $0.2 million, with a weighted average remaining period of 0.4 years.
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Notes to Consolidated and Combined Financial Statements
Performance Stock Unit Awards
During 2017, the Company granted performance stock unit awards (“PSUs”) to certain of its officers, which vest based on continuous employment and satisfaction of a performance metric based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR of a peer group of companies over an approximate three-year performance period ending December 31, 2019. The number of shares which may ultimately be earned ranges from zero to 200% of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over approximately three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.
A summary of PSU award activity for the year ended December 31, 2017 is as follows:
The grant-date fair value of the PSUs was determined using a Monte Carlo simulation, which uses a probabilistic approach for estimating the fair value of the awards. The expected volatility was derived from a weighted combination of implied volatility and historical volatility. The risk-free interest rate was determined using the yield available for zero-coupon U.S. government issues with remaining terms corresponding to the service periods of the PSUs.
The following table presents information regarding the weighted average fair value for PSUs granted during the year ended December 31, 2017 and the assumptions used to determine the fair values:
Note 7-Earnings Per Share
Basic earnings per share (“EPS”) is computed by dividing net earnings by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested RSUs and PSUs, if including such potential shares of common stock units is dilutive. The PSUs included in the calculation of diluted weighted average shares outstanding are based on the number of shares of common stock that would be issuable if the end of the reporting period was the end of the performance period required for the vesting of such PSU awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all awards is anti-dilutive.
For the year ended December 31, 2017, the Company’s EPS calculation includes only the net loss for the period subsequent to the corporate reorganization and IPO, and omits income or loss prior to these events. In addition, the basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the period from January 27, 2017, to December 31, 2017.
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Notes to Consolidated and Combined Financial Statements
A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
The following table presents amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be anti-dilutive:
(1)
When the Company incurs a net loss, all outstanding equity awards are excluded from the calculation of diluted loss per common share because the inclusion of these awards would be anti-dilutive.
Note 8-Income Taxes
JPE LLC was organized as a limited liability company and treated as a pass-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and included in their tax returns. Accordingly, provision for federal and state corporate income taxes has been made only for the operations of the Company from January 27, 2017 through December 31, 2017 in the accompanying consolidated and combined financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the change in tax status as a result of the corporate reorganization, the Company established an $80.7 million provision for deferred income taxes, which was recognized as tax expense from continuing operations.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"). The Tax Act, among other things, (i) permanently reduces the U.S. corporate income tax rate to 21%, (ii) repeals the corporate alternative minimum tax, (iii) imposes new limitations on the utilization of net operating losses and eliminates their carryforward restrictions and (iv) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense. In addition, the Tax Act preserves deductibility of intangible drilling costs and provides for 100% bonus depreciation on tangible personal property expenditures through 2022. The bonus depreciation percentage is phased down from 100% beginning in 2023 to 0% for years after 2026. The Company recognizes the effects of changes in tax laws and rates on deferred tax assets and liabilities and the retroactive effects of changes in tax laws in the period in which the new legislation is enacted or signed into law.
The SEC issued rules that would allow for a measurement period of up to one year after the enactment date of the Tax Act to finalize the impact of the Tax Act on a company's financial statements. The Company has substantially completed the analysis of the Tax Act and does not expect a material change due to the transition impacts. Any changes that do arise due to changes in interpretations of the Tax Act, legislative action to address questions that arise because of the Tax Act, changes in
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Notes to Consolidated and Combined Financial Statements
accounting standards for income taxes or related interpretations in response to the Tax Act, or any updates or changes to estimates the Company has utilized to calculate the transition impacts will be disclosed in future periods as they arise.
The components of the Company’s provision for income taxes are as follows:
A reconciliation of the income tax expense calculated at the federal statutory rate of 35% to the total income tax expense is as follows:
Prior to the Company’s change in tax status in January 2017, income taxes did not significantly impact the results of operations. The equity-based compensation related to shares of common stock transferred to Management Holdco is not deductible for federal or state income tax purposes. See Note 6, Equity-based Compensation, for more information on the shares of common stock transferred to Management Holdco.
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Notes to Consolidated and Combined Financial Statements
The components of the Company’s deferred income tax assets and liabilities as of December 31, 2017 are as follows:
The Company had U.S. net operating losses of approximately $16.1 million, which expire in 2037. Deferred tax assets are reduced by a valuation allowance if the Company believes it is more likely than not such deferred tax assets will not be realized. The Company periodically assesses its deferred tax assets for realizability and, as a result of such assessment, determined as of December 31, 2017 sufficient evidence existed to indicate it is more likely than not that its deferred tax assets will be realized.
The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. That Company gives financial statement recognition to those tax provisions that it believes are more likely than not to be sustained upon examination by the Internal Revenue Service or other government agency. As of December 31, 2017, the Company did not have any accrued liability for unrecognized tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. At December 31, 2017, the Company has made no provisions for interest or penalties related to uncertain tax positions.
The Company files income tax returns in the U.S. federal jurisdiction, Texas and Colorado. There are currently no federal or state income tax examinations underway. The Company’s U.S. federal income tax returns remain open to examination by the taxing authorities for tax years 2014 through 2017, and its Texas and Colorado tax returns remain open to examination for the years 2013 through 2017.
Note 9-Asset Retirement Obligations
The following table summarizes the changes in the carrying amount of the ARO liabilities for the years ended December 31, 2017 and 2016. Any ARO classified as current is included in accrued liabilities on the consolidated and combined balance sheets.
In 2017 and 2016, the Company recognized revisions of estimated liabilities totaling $9 thousand and $0.2 million, respectively, which were due to changes in working interest and estimated abandonment timing and costs.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Note 10-Commitments and Contingencies
Commitments
The table below shows the Company’s future minimum payments under noncancelable operating leases and other commitments as of December 31, 2017:
(1)
Primarily relates to the lease of the Company’s corporate offices.
(2)
Primarily relates to a retail power sales agreement and seismic data gathering contract.
Office and equipment operating lease commitments
The Company leases office space in Denver, Colorado, and Midland, Texas. The Company’s lease for its initial corporate office space in Denver expires in September 2018, and in December 2017 the Company moved into a new corporate office space. The Company’s new corporate office lease in Denver expires in 2028. In connection with this lease, the Company received $4.7 million of lease incentives primarily related to tenant improvements, which is recorded within other long-term liabilities on the consolidated and combined balance sheets. The lease incentive liability is amortized on a straight-line basis as a reduction to rent expense over the lease term. The tenant improvements are depreciated over the shorter of the useful life of the asset or the life of the lease. The Company also leases certain office equipment under operating leases, which expire over the next five years.
Rent expense with respect to these lease commitments was approximately $0.9 million for the year ended December 31, 2017, and $0.6 million for each of the years ended December 31, 2016 and 2015.
In January 2018, the Company entered into a termination agreement on its initial corporate office lease, in which the Company agreed to a one-time termination fee of approximately $0.3 million. Including this fee, the 2018 operating lease commitment would be $1.8 million.
Drilling rig commitments
At December 31, 2017, the Company had six drilling rigs under contract. If the Company were to terminate these contracts at December 31, 2017, it would be required to pay early termination penalties of $7.5 million. In 2016 and 2015, the Company terminated one drilling rig in each year and incurred early termination charges of approximately $0.2 million and $0.3 million, respectively. These charges are reflected as other operating costs on the consolidated and combined statements of operations.
Frac fleet commitments
At December 31, 2017, the Company had three frac fleets under contract through December 31, 2018. The majority of the contracts allow for reassignment of the frac fleets to another operator if the Company were to terminate their services prior to the end of the contract, at which point the Company would not be required to pay termination fees. However, if the fleets were not able to be reassigned, the Company would be required to pay termination fees of $57.2 million as of December 31, 2017.
Contingencies
Legal Matters
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
Environmental Matters
The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both December 31, 2017 and 2016, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.
Note 11-Related Party Transactions
Quantum employs certain members of the Company’s board of directors and had significant capital interests in JPE LLC. As of December 31, 2017, Quantum owns 68.7% of the Company’s common stock.
Quantum owns a 41.5% interest in Oryx Midstream Services, LLC (together with Oryx Southern Delaware Holdings, LLC, “Oryx”). The Company has a 12-year crude oil gathering agreement with Oryx whereby Oryx provides midstream gathering services to the Company. Under that agreement, the Company has the right to designate, and has designated, a third-party shipper to market the Company’s crude oil. In addition, the Company paid fees to Oryx for the purchase and maintenance of connecting equipment.
Quantum also owns a 60.9% interest in Phoenix Lease Services, LLC (“Phoenix”), and an indirect interest in Trident Water Services, LLC (“Trident”), a wholly owned subsidiary of Phoenix. The Company regularly leases frac tanks and other oil field equipment from Phoenix, and regularly uses water transfer services provided by Trident. The Company is under no obligation to use either provider, and both provide services only when selected as a vendor through the Company’s normal bidding process.
The following table summarizes fees paid to Oryx, Phoenix and Trident for the periods indicated:
(1)
Transportation fees paid by the Company’s third-party shipper to Oryx pursuant to the crude oil gathering agreement are netted against revenue as they are included in the net price paid by to the third-party shipper.
(2)
Fees paid to Oryx for the purchase and installation of connecting equipment are capitalized to proved properties on the consolidated and combined balance sheets.
(3)
Fees paid to Phoenix and Trident are capitalized to proved properties on the consolidated and combined balance sheets.
At December 31, 2017 and 2016, the Company had outstanding payables to these related parties of $1.8 million and $0.7 million, respectively.
Supplemental Oil and Natural Gas Disclosures (Unaudited)
Oil and Gas Exploration and Production Activities
The Company has only one reportable operating segment, which is oil and gas development, exploration and production in the United States. See the Company’s accompanying consolidated and combined statements of operations for information about results of operations for oil and gas producing activities. The amounts shown include the Company’s net working interests in all of its oil and gas properties.
Capitalized Costs Relating to Oil and Gas Producing Activities
Aggregate capitalized costs related to the Company’s oil and natural gas producing activities at December 31, 2017 and 2016 were as follows:
Costs Incurred for Oil and Gas Activities
Costs incurred for the Company’s oil and natural gas activities for the years ended December 31, 2017, 2016 and 2015 were as follows:
(1)
Includes amounts related to estimated asset retirement costs of $0.6 million, $22 thousand and $0.2 million for the years ended December 31, 2017, 2016 and 2015, respectively. The increase to the Company’s asset retirement estimate for the year ended December 31, 2017, as compared to 2016, is primarily due to the estimated abandonment costs on the 46.1 net wells that began producing during 2017.
Oil and Natural Gas Reserve Quantities
The Company’s proved oil and natural gas reserves are all located in the United States, within the Delaware Basin, a sub-basin of the Permian Basin of West Texas. All of the estimates of the proved reserves at December 31, 2017, 2016 and 2015 are based on reports prepared by Ryder Scott Company, LP, the Company’s independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.
Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e. costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. A variety of methodologies are used to determine the Company’s proved reserve estimates. The primary methodologies used are decline curve analysis, advance production type curve matching, petrophysics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates across substantially all the Company’s properties. Reserve estimates are inherently imprecise, and estimates of undeveloped locations are more imprecise than estimates of established proved producing locations. Accordingly, the Company’s reserve estimates are expected to change as future information becomes available.
Supplemental Oil and Natural Gas Disclosures (Unaudited)
Proved oil and natural gas reserves were calculated based on the prices for oil and natural gas during the 12-month period before the reporting date, determined as the unweighted average of the first-day-of-the-month pricing. For oil and natural gas liquids volumes, the benchmark WTI posted price is adjusted for quality, transportation fees and regional price differentials. For gas volumes, the Henry Hub spot price is adjusted for energy content, transportation fees and regional price basis differentials. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows.
The following table summarizes the average adjusted product prices for 2017, 2016 and 2015:
In addition, the SEC requires that reserves classified as proved undeveloped be capable of conversion into proved developed within five years of classification unless specific circumstances justify a longer time. The Company’s development plans at December 31, 2017 related to scheduled drilling over the next five years are subject to many uncertainties and variables, including availability of capital, future oil and natural gas prices, cash flows from operations, future drilling costs, demand for oil and natural gas and other economic factors.
The following table sets forth information regarding the Company’s estimated net total proved and proved developed oil and natural gas reserve quantities:
Supplemental Oil and Natural Gas Disclosures (Unaudited)
2017 Activity. During 2017, the Company’s estimated proved reserves increased by 44.7 MMBoe to 82.4 MMBoe, compared to 37.7 MMBoe at year end 2016. The increase in proved reserves during 2017 was largely due to 51.8 MMBoe added through extensions and discoveries, due to 46.1 net new wells that began producing in 2017 and adding 49 gross (45.0 net) PUD locations. The Company’s revisions of previous estimates were primarily the result of 2.2 MMBoe of negative revisions related to higher operating costs, partially offset by positive revisions due to pricing (0.6 MMBoe) and technical revisions (0.6 MMBoe).
2016 Activity. During 2016, the Company’s estimated proved reserves increased by 24.7 MMBoe to 37.7 MMBoe, compared to 13.0 MMBoe at year end 2015. The increase in proved reserves during 2016 was largely due to 25.2 MMBoe added through extensions and discoveries, due to new wells completed in 2016 and adding 25 gross (23.9 net) PUD locations.
2015 Activity. Estimated proved reserves at December 31, 2015 were 13.0 MMBoe, compared to 2.6 MMBoe at December 31, 2014. The increase in proved reserves during 2015 was primarily related to the Company’s drilling activities. During 2015, the Company drilled and completed seven gross (6.4 net) wells and added nine gross (8.6 net) PUD locations, leading to a combined increase of 10.8 MMBoe of extensions and discoveries.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure is calculated in accordance with guidance provided by the FASB, and is computed by applying the adjusted 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference, including the reduced rate effective for years after 2017 due to the Tax Act.
The assumptions used to calculate estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. If reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized. Future development and production costs are calculated by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions.
The 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves, and is prescribed by GAAP.
With regard to the future income taxes, the Company’s predecessor was a limited liability company, therefore a pass through entity for tax purposes. The effect of future net income taxes has been excluded from the standardized measure of discounted future net cash flows for 2016 and 2015 as the Company’s predecessor was not subject to federal income taxes. The Company’s predecessor was, however, subject to the Texas franchise tax, which is an entity-level tax at a statutory rate of up to 1.0% of a portion of gross revenue apportioned to Texas.
The following table presents the standardized measure of discounted net cash flows related to proved oil and gas reserves as of December 31, 2017, 2016 and 2015:
Supplemental Oil and Natural Gas Disclosures (Unaudited)
A summary of principal sources of changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2017, 2016 and 2015 is as follows:
Supplemental Quarterly Financial Data (Unaudited)
The following tables provide selected quarterly financial data derived from the Company’s consolidated and combined financial statements for the years ended December 31, 2017 and 2016 (in thousands, except per share data):
(1)
The Company’s EPS calculation for the first quarter of 2017 includes only the net loss for the period subsequent to the corporate reorganization and IPO, and omits income or loss prior to these events. In addition, the basic weighted average shares outstanding that were used in the calculation of the first quarter 2017 EPS calculation is based on the actual days in which the shares were outstanding for the period from January 27, 2017, to March 31, 2017. See Note 7, Earnings per Share, for more details.
Net income (loss) for each respective quarter include the following items:
First-quarter 2017:
•
$379.0 million charge to equity-based compensation related to management incentive units in JPE LLC that vested at the time of the IPO (see Note 1, Organization, Operations and Basis of Presentation, and Note 6, Equity-based Compensation).
•
$79.1 million income tax expense related to a change in tax status resulting from the corporate reorganization, which occurred in connection with the IPO (see Note 1, Organization, Operations and Basis of Presentation, and Note 8, Income Taxes).
Fourth-quarter 2017:
•
$58.5 million net loss related to derivative instruments (see Note 3, Derivative Instruments).
•
$37.3 million income tax benefit related to the impact of new income tax legislation (see Note 8, Income Taxes).