ITEM 1.    BUSINESS

Overview

EP Energy Corporation (EP Energy), a Delaware Corporation formed in 2013, is an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States.

We operate through a diverse base of producing assets and are focused on creating shareholder value through the development of our low-risk drilling inventory located in three core areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas) and the Altamont Field in the Uinta Basin (Northeastern Utah). In these areas, we have identified 5,156 drilling locations (including 639 drilling locations to which we have attributed proved undeveloped reserves as of December 31, 2016 , of which 100% are considered oil wells). At current activity levels, this represents approximately 53 years of drilling inventory. As of December 31, 2016 , we had proved reserves of 432.4  MMBoe (51% oil and 72% liquids) and for the year ended December 31, 2016 , we had average net daily production of 87,641 Boe/d ( 53% oil and 70% liquids).

Each of our core areas is characterized by a long-lived reserve base and high drilling success rates. We have established significant contiguous leasehold positions in each core area, representing approximately 452,000 net (605,000 gross) acres in total.

We evaluate growth opportunities in our portfolio that are aligned with our core competencies and that are in areas that we believe can provide us a competitive advantage. Strategic acquisitions of leasehold acreage or acquisitions of producing assets can provide opportunities to achieve our long-term goals by leveraging existing expertise in our core areas, balancing our exposure to regions, basins and commodities, helping us to achieve risk-adjusted returns competitive with those available within our existing drilling program and by increasing our reserves. We continuously evaluate our asset portfolio and will sell oil and natural gas properties if they no longer meet our long-term goals.

The following table provides a summary of oil, natural gas and NGLs reserves as of December 31, 2016 and production data for the year ended December 31, 2016 for each of our areas of operation.

(2)    Includes 15 MMBoe of proved developed non-producing reserves representing 3% of total net proved reserves at December 31, 2016 .

Approximately 190 MMBoe, or 44%, of our total proved reserves are proved developed producing assets, which generated average production of 87.6 MBoe/d in 2016 from approximately 1,470  wells. As of December 31, 2016 , we had approximately 220  MMBbls of proved oil reserves, 91  MMBbls of proved NGLs reserves and 732  Bcf of proved natural gas reserves, representing 51%, 21% and 28%, respectively, of our total proved reserves. For the year ended December 31, 2016 , 70% of our production was related to oil and NGLs versus 69% in 2015 and over that same period and on that same basis, our oil production decreased by approximately 23% as a result of lower capital spending levels in 2015 and 2016. 

We operate 91% of our producing wells and have operational control over approximately 98% of our drilling inventory as of December 31, 2016 . This control provides us with flexibility around the amount and timing of capital spending and has allowed us to continually improve our capital and operating efficiencies. In 2016, we realized 17% in capital cost and 12% in operating cost savings across our programs. We also employ a centralized drilling and completion structure to accelerate our internal knowledge transfer around the execution of our drilling and completion programs. In 2016 , we drilled 98  wells with a success rate of 100%, adding approximately 64 MMBoe of proved reserves (66% of which were liquids). As of December 31, 2016 , we also had a total of 58 wells drilled, but not completed across our programs.

Our Properties

Eagle Ford Shale .  The Eagle Ford Shale, located in South Texas, is one of the premier unconventional oil plays in the United States. We were an early entrant into this play in late 2008, and since that time have acquired a leasehold position in the core of the oil window, primarily in La Salle County. The Eagle Ford formation in La Salle County has up to 125 feet of net thickness (165 feet gross). Due to its high carbonate content, the formation is also very brittle, and exhibits high productivity when fractured.  In 2015, we acquired approximately 12,000 net acres adjacent to our existing Eagle Ford Shale assets. As of December 31, 2016 , we had 93,227 net ( 104,122 gross) acres in the Eagle Ford, and have identified 894 drilling locations.

During 2016 , we invested $175 million in capital in our Eagle Ford Shale and operated an average of one drilling rig.  As of December 31, 2016 , we had 607 net producing wells (598 net operated wells) and are currently running one rig in this program. For the year ended December 31, 2016 , our average net daily production was 43,487 Boe/d, representing a decrease of 25% over the same period in 2015 due to natural declines and the slower pace of development from reduced capital spending in 2016.  For the year ended December 31, 2016 our average cost per gross well was $4.2 million ($4.1 million per net well), representing a 28% decline from our average cost per gross well (25% per net well) compared to the year ended December 31, 2015 .

Wolfcamp Shale .  The Wolfcamp Shale is located in the Permian Basin. The Permian Basin is characterized by numerous, stacked oil reservoirs that provide excellent targets for horizontal drilling. In 2009 and 2010, we leased 138,130 net (138,469 gross) acres on the University of Texas Land System in the Wolfcamp Shale, located primarily in Reagan, Crockett, Upton and Irion counties.

Our large, contiguous acreage positions are characterized by stacked pay zones, including the Wolfcamp A, B, and C zones, which combine for over 750 feet of net (approximately 1,000 feet of gross) thickness. The Wolfcamp has high organic content and is composed of interbedded shale, silt, and fine-grained carbonate that respond favorably to fracture stimulation.  As of December 31, 2016 , we had 178,024 net ( 178,362 gross) acres in the Wolfcamp, and have identified approximately 2,937 drilling locations in the Wolfcamp A, B, and C zones.

The acreage is also prospective for the Cline Shale, which has approximately 100 feet of net (approximately 200 feet of gross) thickness, and potential vertical drilling locations in the Spraberry and other stacked formations.

During 2016 , we invested $233 million in capital in our Wolfcamp Shale and operated an average of approximately one drilling rig. As of December 31, 2016 , we had 290 net producing wells (287 net operated wells). We are currently running two rigs in this program.  For the year ended December 31, 2016 , our average net daily production was 21,371 Boe/d, representing an increase of 8% over 2015 reflecting a higher allocation of capital to this strategic program.  For the year ended December 31, 2016 , our average cost per gross and net well was $4.6 million, representing a 13% decline from our average cost per gross and net well compared to the year ended December 31, 2015 .

In May 2016, we amended our Wolfcamp development agreement with the University Lands to provide flexibility to extend the time frame to hold our acreage by nearly four years to the end of 2021, with an increase in annual well completion requirements from six wells per year to 34 , 55 and 55 wells per year in 2016, 2017 and 2018, respectively. In addition, the amendment includes a sliding scale royalty framework that improves well returns in a lower price environment. The royalty rates associated with the sliding scale framework are determined using a rolling average six month price with royalty rates of 12.5% at an average price of $50 per Bbl (WTI) and below, 18.75% at an average price of $60 per Bbl (WTI) and below, 25% at an average price of $80 per Bbl (WTI) and below and 28% above $80 per Bbl (WTI).

In January 2017, we entered into a drilling joint venture to accelerate and fund future oil and natural gas development in our Wolfcamp program.  Under the joint venture, our partner is participating in the development of up to 150 wells in two separate 75 well tranches primarily in Reagan and Crockett counties.  We will retain operational control of the joint venture assets and the transaction is expected to increase the Company's well-level returns on the jointly developed wells.  The first wells under the joint venture began production in January 2017. For a further discussion of this joint venture, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Our Business” and Item 8, “Financial Statements and Supplementary Data”, Note 11.

Altamont .  The Altamont field is located in the Uinta Basin in northeastern Utah. The Uinta Basin is characterized by naturally fractured, tight-oil sands and carbonates with multiple pay zones. Our operations are primarily focused on developing the Altamont Field Complex (comprised of the Altamont, Bluebell and Cedar Rim fields), which is the largest field in the basin. We own 180,980 net ( 322,677 gross) acres in Duchesne and Uinta Counties. The Altamont Field Complex has a gross pay interval thickness of over 4,300 feet and we believe the Wasatch and Green River formations are ideal targets for low-risk, infill, vertical drilling and modern fracture stimulation techniques. Our commingled production is from over 1,500 feet of net

stimulated rock. Our current activity is mainly focused on the development of our vertical inventory on 80-acre and 160-acre spacing. As of December 31, 2016 , we had identified 1,325 drilling locations. Industry activity has also focused on horizontal drilling in the Wasatch and Green River formations testing tight carbonate and sand intervals and has also piloted 80-acre vertical downspacing in these formations. Due to the largely held-by-production nature of our acreage position, if these programs are successful, they will result in additional vertical and horizontal drilling opportunities that could be added to our inventory of drilling locations.

During 2016 , we invested $76 million in capital in the Altamont Field and operated an average of one drilling rig. As of December 31, 2016 , we had 382 net producing wells (373 net operated wells) and are currently running two rigs in this program.  For the year ended December 31, 2016 , our average net daily production was 16,498 Boe/d, representing a decrease of 4% over 2015 due to natural declines and slower pace of development from reduced capital spending in 2016.  For the year ended December 31, 2016 our average cost per gross well was $4.1 million ($2.8 million per net well), the same as our average cost per gross well (a 22% decline per net well) compared to the year ended December 31, 2015 .

Haynesville Shale .  In May 2016, we completed the sale of our assets located in the Haynesville and Bossier shales for approximately $420 million (net cash proceeds of $388 million after customary adjustments) and recorded a gain on the sale of approximately $79 million. Prior to its sale, we had invested $3 million in capital in the Haynesville Shale in 2016 and for the year ended December 31, 2016 , our average net daily production was 37  MMcf/d.

The following table provides a summary of acreage and inventory data in our core areas as of December 31, 2016 :

(1)    Our inventory as of December 31, 2016 does not include the following potential additional locations:

We have used the data from our development programs to identify and prioritize our inventory. These drilling locations are only included in our inventory after they have been evaluated technically.

Our reserves in the table above are consistent with estimates of reserves filed with other federal agencies except for differences of less than 5% resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience.  Our estimated net proved reserves were prepared by our internal reserve engineers and audited by Ryder Scott Company, L.P. (Ryder Scott), our independent petroleum engineering consultants.

The table below presents net proved reserves as reported and sensitivities related to our estimated proved reserves based on differing price scenarios as of December 31, 2016 .

The sensitivities in the table above were based on the average first day of the month spot price for the preceding 12-month period of $42.75 per barrel of oil (WTI) and $2.48 per MMBtu of natural gas (Henry Hub) used to determine net proved reserves at December 31, 2016 .

We employ a technical staff of engineers and geoscientists that perform technical analysis of each undeveloped location. The staff uses industry accepted practices to estimate, with reasonable certainty, the economically producible oil and natural gas. The practices for estimating hydrocarbons in place include, but are not limited to, mapping, seismic interpretation of two-dimensional and/or three-dimensional data, core analysis, mechanical properties of formations, thermal maturity, well logs of existing penetrations, correlation of known penetrations, decline curve analysis of producing locations with significant production history, well testing, static bottom hole testing, flowing bottom hole pressure analysis and pressure and rate transient analysis.

Our primary internal technical person in charge of overseeing our reserves estimates has a B.S. degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers. He is the executive vice president and chief operating officer of the company.  In this capacity, he is responsible for the Company’s operating divisions, drilling and completions, and our Marketing group.  He also oversees the reserve reporting and technical support groups. He has more than 28 years of industry experience in various domestic and international engineering and management roles. For a discussion of the internal controls over our proved reserves estimation process, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Estimates”.

Ryder Scott conducted an audit of the estimates of net proved reserves that we prepared as of December 31, 2016 .  In connection with its audit, Ryder Scott reviewed 99% (by volume) of our total net proved reserves on a barrel of oil equivalent basis, representing 98% of the total discounted future net cash flows of these net proved reserves.  For the audited properties, 100% of our total net proved undeveloped (PUD) reserves were evaluated.  Ryder Scott concluded that the overall procedures and methodologies that we utilized in preparing our estimates of net proved reserves as of December 31, 2016 complied with current SEC regulations and the overall net proved reserves for the reviewed properties as estimated by us are, in aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the Society of Petroleum Engineers auditing standards.  Ryder Scott’s report is included as an exhibit to this Annual Report on Form 10-K.

The technical person primarily responsible for overseeing the reserves audit by Ryder Scott has a B.S. degree in chemical engineering. He is a Licensed Professional Engineer in the State of Texas, a member of the Society of Petroleum Engineers and has more than 13 years of experience in petroleum reserves evaluation.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties with proved reserves, or both, our proved reserves will decline as they are produced. Recovery of PUD reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change. In addition, estimates of PUD reserves and proved non-producing reserves are inherently subject to greater uncertainties than estimates of proved producing reserves. For further discussion of our reserves, see Part II, Item 8, Financial Statements and Supplementary Data, under the heading Supplemental Oil and Natural Gas Operations.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2016 , we have 228 MMBoe of PUD reserves and 639 PUD locations within our areas, all of which are scheduled to be developed or drilled within five years of their initial recording. Estimated capital expenditures to develop our PUD reserves (convert PUD reserves to proved developed reserves) are based upon a long-range plan approved by the Board of Directors. All PUD locations are surrounded by producing properties, and a majority of our PUDs directly offset a producing property. Where we have recorded PUDs beyond one location away from a producing property, reasonable certainty of economic producibility has been established by reliable technology in our areas, including field tests that demonstrate consistent and repeatable results within the formation being evaluated.

We assess our PUD reserves on a quarterly basis. The following table summarizes our changes in PUDs for the years ended December 31, 2015 and December 31, 2016 , respectively (in MMBoe):

    

Purchases of minerals in place are PUD reserves acquired in one or more of our core areas in 2015. Extensions and discoveries in 2015 and 2016 are primarily related to drilling activities in the Eagle Ford, Wolfcamp and Altamont areas. Revisions due to prices represent PUD revisions due to decreases in commodity prices (using SEC 12-month average pricing). For the year ended December 31, 2016 , revisions other than prices, includes, among other items, negative revisions of 98 MMBoe due to reductions in our estimated capital in our five year development plan, partially offset by positive PUD revisions of 17 MMBoe due to ownership revisions. For the year ended December 31, 2015 , revisions other than prices, includes negative PUD revisions of 85 MMBoe due to the impact of the SEC's five-year development rule after reductions in the estimated capital in our 2015 long-range development plan based on the lower price environment.

As of December 31, 2016 , 25 MMBoe or 11% of our PUDs had a positive undiscounted value, but a negative value when discounted at 10 percent.  A majority of these discounted negative value PUD reserves are due to leasehold commitments associated with continuous drilling clauses. During 2016 , 2015 and 2014 , we spent approximately $281 million, $835 million and $1,192 million, respectively, to convert approximately 9% or 25 MMBoe, 14% or 55 MMBoe and 20% or 75 MMBoe, respectively, of our prior year-end PUD reserves to proved developed reserves.  The lower conversion rates are a result of reductions in actual capital spending compared to what was planned in response to the significant downturn in prices that has continued since the fourth quarter of 2014. In 2017 , 2018 and 2019 we estimate we will spend approximately $473 million, $496 million and $541 million to develop our PUD reserves, respectively, based on our December 31, 2016 internal reserve report. At this level of spending from 2017 through 2019, we will develop approximately 60% of our existing PUD reserves with the remaining balance of PUDs to be developed in the succeeding two years. We believe we have the ability and have the intent to develop our PUDs over five years based on our strategic plan. The actual amount and timing of our forecasted expenditures will depend on a number of factors, including actual drilling results, service costs and future commodity prices which are currently and could in the future be lower than those in our projected long-range plan.

(1)    Gross interest reflects the total acreage we participate in regardless of our ownership interest in the acreage.

(2)    Net interest is the aggregate of the fractional working interests that we have in the gross acreage.

Our net developed acreage is concentrated in Utah (50%) and Texas (49%). Our net undeveloped acreage is concentrated in Texas (49%), Utah (28%), Wyoming (11%) and West Virginia (10%). Approximately 2%, 3% and 2% of our net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2017, 2018 and 2019, respectively. We employ various techniques to manage the expiration of leases, including drilling the acreage ourselves prior to lease expiration, entering into farm-out or joint development agreements with other operators or extending lease terms.

(1)    Comprised of wells that were spud as of December 31, 2016 and have not been completed.

(2)    Gross interest reflects the total wells we participated in, regardless of our ownership interest.

(3)    Net interest is the aggregate of the fractional working interests that we have in the gross wells or gross wells drilled.

(4)    At December 31, 2016 , we operated 1,259 of the 1,279 net productive wells.

(1)    Net interest is the aggregate of the fractional working interests that we have in the gross wells or gross wells drilled.

(2)    December 31, 2015 includes 4 net development wells in our Haynesville Shale which was sold in May 2016.

The drilling performance above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered.

Net Production, Sales Prices, Transportation and Production Costs

The following table details our net production volumes, net production volume by area, average sales prices received, average transportation costs, average lease operating expense and average production taxes associated with the sale of oil, natural gas and NGLs for each of the three years ended December 31:

Acquisition, Development and Exploration Expenditures

See Part II, Item 8, Financial Statements and Supplementary Data under the heading Supplemental Oil and Natural Gas Operations in the Total Costs Incurred table for details on our acquisition, development and exploration expenditures.

Transportation, Markets and Customers

Our marketing strategy seeks to ensure maximum deliverability of our physical production at the maximum realized prices. We leverage knowledge of markets and transportation infrastructure to enter into beneficial downstream processing, treating and marketing contracts. We primarily sell our domestic oil and natural gas production to third parties at spot market prices, while we sell our NGLs at market prices under monthly or long-term contracts. We typically sell our oil production to a relatively small number of creditworthy counterparties, as is customary in the industry. For the year ended December 31, 2016 , five purchasers accounted for approximately 69% of our oil revenues: Flint Hills Resources, LP (an affiliate of Koch Industries), Shell Trading U.S. Co. (an affiliate of Shell Oil Company), JP Energy Products Supply, LLC, Big West Oil LLC and BP Oil Supply (a division of BP P.L.C). Across all of our areas, we maintain adequate gathering, treating, processing and transportation capacity, as well as downstream sales arrangements, to accommodate our production volumes.

In our Eagle Ford Shale area, we are connected to the Camino Real oil gathering system and to the NuStar Energy system.  The vast majority of our oil production flows on Camino Real, a 68-mile long pipeline with over 110,000 Bbls/d of capacity and a gravity bank that allows for oil blending to maintain attractive API levels. We have 80,000 Bbls/d of firm capacity on this oil system, of which we utilized an average of 30% during December  2016 and 38% on average for the year.  The system delivers oil to the Storey Oil Terminal on Highway 97 east of Cotulla, Texas, six miles southeast of Gardendale, Texas.  From the Storey Terminal, oil can be pumped into Harvest’s Arrowhead #1 and/or #2 pipelines, as well as the Plains All American Pipeline connection to the Gardendale Hub.  Oil can also be loaded into trucks out of the Storey Terminal or out of the numerous central tank batteries throughout our field, providing additional deliverability, reliability and flexibility.  We currently market our oil either at the Storey Terminal, Gardendale or at our central tank batteries under a combination of short and long-term contracts, ranging from monthly deals to multi-year term sales. With adequate takeaway capacity in the region and close proximity to the Gulf Coast refining complex, we believe we have sufficient capacity on our contracts and do not anticipate any issues with marketing and delivering volumes from the Eagle Ford Shale. 

Our Eagle Ford natural gas production flows on either the Camino Real gas gathering system or the Frio LaSalle Pipeline system with the majority flowing on the Camino Real gas gathering system. The Camino Real gas gathering system receives high-pressure, unprocessed wellhead gas into an 83-mile pipeline with capacity up to 150 MMcf/d.  The gas is then redelivered into interconnects with Energy Transfer, Enterprise, Regency and Eagle Ford Gathering.  We currently have 125 MMcf/d of firm transportation capacity on Camino Real, of which we used an average of 43% during December  2016 , and we have additional capacity available as needed.  We have firm gas gathering, processing and transportation agreements on three of the interconnected gas pipelines downstream of the Camino Real system, with a minimum capacity of approximately 100 MMBtu/d and rights to increase firm capacity as necessary.  In addition, gas produced from our northwest acreage position within the Eagle Ford area is connected to the Frio LaSalle Pipeline system, which provides access to firm H2S treating and processing.  Frio LaSalle can either return gas to the Camino Real system or, after processing, deliver to various Texas intrastate pipelines and a mix of interstates, such as Texas Eastern Transmission, Tennessee Gas Pipeline, and Transco. We market our physical gas to various purchasers at spot market prices. 

In our Wolfcamp Shale area, we continue to leverage significant legacy gathering, processing and transportation infrastructure. For natural gas, we are connected to the West Texas Gas (WTG), DCP and Lucid Energy Group gathering systems, and we process a majority of our gas at the WTG Benedum & Sonora gas plants. We receive Waha pricing for our natural gas and Mont Belvieu pricing for our NGLs. “Waha pricing” refers to the published index price for spot and monthly physical natural gas purchases and sales made into interstate and intrastate pipelines at the outlet of the Waha header system and in the Waha vicinity in the Permian Basin in West Texas. “Mont Belvieu pricing” refers to the spot market price for NGLs delivered into the Mont Belvieu NGL processing and storage hub in Mont Belvieu, Texas. Our crude oil production facilities are connected to a third party oil gathering system that delivers to a Plains All American Pipeline at Owens Station in Reagan County, Texas, the Centurion Cline Shale Pipeline at Barnhart in Irion County, Texas and to the Magellan Longhorn pipeline in Crockett County, Texas. We sell our pipeline delivered crude to multiple purchasers under both short and long-term contracts at WTI-based pricing. We also maintain the capability to truck crude oil to those same purchasers under similarly-priced contracts to provide additional flow assurance. With new Permian Basin takeaway pipelines now online, we anticipate no limitations moving physical crude oil to market and expect regional pricing to remain correlated with NYMEX/WTI.

In our Altamont area, the wax crude we produce is sold at the wellhead to multiple purchasers who transport the oil via truck to downstream refineries. We sell most of the oil we produce in the basin to Salt Lake City refineries under long-term

sales agreements that accommodate our production forecasts. Our produced natural gas is gathered and processed at the Altamont plant, a third-party-owned processing facility, under a long-term sales agreement that provides for residue gas return for operational use.

While most of our physical production is priced off spot market indices, we actively manage the volatility of spot market pricing through our risk management program. We enter into financial derivatives contracts on our oil, natural gas and a portion of our NGLs production to stabilize our cash flows, reduce the risk of downward commodity price movements and protect the economic assumptions associated with our capital investment program. We employ a disciplined risk management program that utilizes risk control processes. For a further discussion of these risk management activities and derivative contracts, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

Competitors

The exploration and production business is highly competitive in the search for and acquisition of additional oil and natural gas reserves and in the sale of oil, natural gas and NGLs. Our competitors include major and intermediate sized oil and natural gas companies, independent oil and natural gas operators and individual producers or operators with varying scopes of operations and financial resources. Competitive factors include financial resources, price and contract terms, our ability to access drilling, completion and other equipment and our ability to hire and retain skilled personnel on a timely and cost effective basis. Ultimately, our future success in this business will be dependent on our ability to find and/or fund the acquisition of additional reserves at costs that yield acceptable returns on the capital invested.

Use of 3-D Seismic Data  

Within our areas we have an inventory of approximately 1,268 square miles of 3-D seismic data providing approximately 50% coverage of our leased acreage in those areas. We use our 3-D seismic data to improve our geologic models for each area. In the Eagle Ford and Wolfcamp areas, detailed maps of structural features (e.g. natural fractures, faulting and stratigraphic discontinuities) are used to position well bore laterals to optimally exploit oil bearing zones and navigate drilling hazards. In the Altamont Field, data analytics are run using 3-D seismic attributes to identify ideal locations in the reservoir and estimate resource distribution. Seismic data sets are continually updated to keep pace with technological advancements in seismic processing.

Regulatory Environment  

Our oil and natural gas exploration and production activities are regulated at the federal, state and local levels in the United States. These regulations include, but are not limited to, those governing the drilling and spacing of wells, conservation, forced pooling and protection of correlative rights among interest owners.  We are also subject to various governmental safety and environmental regulations in the jurisdictions in which we operate.

Our operations under federal oil and natural gas leases are regulated by the statutes and regulations of the Department of the Interior (DOI) that currently impose liability upon lessees for the cost of environmental impacts resulting from their operations. Royalty obligations on all federal leases are regulated by the Office of Natural Resources Revenue within the DOI, which has promulgated valuation guidelines for the payment of royalties by producers. These laws and regulations affect the construction and operation of facilities, water disposal rights and drilling operations, among other items.  In addition, we maintain insurance to limit exposure to sudden and accidental pollution liability exposures.

Hydraulic Fracturing. Hydraulic fracturing is a process of pumping fluid and proppant (usually sand) under high pressure into deep underground geologic formations that contain recoverable hydrocarbons. These hydrocarbon formations are typically thousands of feet below the surface. The hydraulic fracturing process creates small fractures in the hydrocarbon formation. These fractures allow natural gas and oil to move more freely through the formation to the well and finally to the surface production facilities. We use hydraulic fracturing to maximize productivity of our oil and natural gas wells in our areas and our proved undeveloped oil and natural gas reserves will be developed using hydraulic fracturing. For the year ended December 31, 2016 , we incurred costs of approximately $139 million associated with hydraulic fracturing.

Hydraulic fracturing fluid is typically composed of over 99% water and proppant, which is usually sand. The other 1% or less of the fluid is composed of additives that may contain acid, friction reducer, surfactant, gelling agent and scale inhibitor. We retain service companies to conduct such operations and we have worked with several service companies to evaluate, test and, where appropriate, modify our fluid design to reduce the use of chemicals in our fracturing fluid. We have worked closely with our service companies to provide voluntary and regulatory disclosure of our hydraulic fracturing fluids.

In order to protect surface and groundwater quality during the drilling and completion phases of our operations, we follow applicable industry practices and legal requirements of the applicable state oil and natural gas commissions with regard

to well design, including requirements associated with casing steel strength, cement strength and slurry design. Our activities in the field are monitored by state and federal regulators. Key aspects of our field protection measures include: (i) pressure testing well construction and integrity, (ii) casing and cementing practices to ensure pressure management and separation of hydrocarbons from groundwater, and (iii) public disclosure of the contents of hydraulic fracturing fluids.

In addition to these measures, our drilling, casing and cementing procedures are designed to prevent fluid migration, which typically include some or all of the following:

In addition to the required use of casing and cement in the well construction, we follow additional regulatory requirements and industry operating practices. These typically include pressure testing of casing and surface equipment and continuous monitoring of surface pressure, pumping rates, volumes of fluids and chemical concentrations during hydraulic fracturing operations. When any pressure differential outside the normal range of operations occurs, pumping is shut down until the cause of the pressure differential is identified and any required remedial measures are completed. Hydraulic fracturing fluid is delivered to our sites in accordance with Department of Transportation (DOT) regulations in DOT approved shipping containers using DOT transporters.

We also have procedures to address water use and disposal. This includes evaluating surface and groundwater sources, commercial sources, and potential recycling and reuse of treated water sources. When commercially and technically feasible, we use recycled or treated water. This practice helps mitigate against potential adverse impacts to other water supply sources. When using raw surface or groundwater, we obtain all required water rights or compensate owners for water consumption. We are evaluating additional treatment capability to augment future water supplies at several of our sites. During our drilling and completions operations, we manage waste water to minimize environmental risks and costs. Flowback water returned to the surface is typically contained in steel tanks or pits. Water that is not treated for reuse is typically piped or trucked to waste disposal injection wells, a number of which we operate. These wells are permitted through Underground Injection Control (UIC) program of the Safe Drinking Water Act. We also use commercial UIC permitted water injection facilities for flowback and produced water disposal.

We have not received regulatory citations or notice of suits related to our hydraulic fracturing operations for environmental concerns. We have not experienced a surface release of fluids associated with hydraulic fracturing that resulted in material financial exposure or significant environmental impact. Consistent with local, state and federal requirements, releases are reported to appropriate regulatory agencies and site restoration completed. No remediation reserve has been identified or anticipated as a result of hydraulic fracturing releases experienced to date.

Spill Prevention/Response Procedures. There are various state and federal regulations that are designed to prevent and respond to any spills or leaks resulting from exploration and production activities. In this regard, we maintain spill prevention control and countermeasures programs, which frequently include the installation and maintenance of spill containment devices

designed to contain spill materials on location. In addition, we maintain emergency response plans to minimize potential environmental impacts in the event of a spill or leak or any significant hydraulic fracturing well control issue.

Environmental

A description of our environmental remediation activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 9.

Employees

As of February 28, 2017, we had 502 full-time employees in the United States.

Executive Officers of the Registrant

Our executive officers as of February 28, 2017, are listed below.

Brent J. Smolik

Mr. Smolik has been our President, Chief Executive Officer and Chairman of the Board since August 30, 2013, President and Chief Executive Officer of EP Energy LLC since May 2012 and previously served as Chairman of the Board of Managers of EPE Acquisition, LLC, from May 2012 to August 2013. He was previously Executive Vice President and a member of the Executive Committee of El Paso Corporation and President of our predecessor, EP Energy Corporation (a/k/a El Paso Exploration & Production Company) from November 2006 to May 2012. Mr. Smolik was President of ConocoPhillips Canada from April 2006 to October 2006. Prior to the Burlington Resources merger with ConocoPhillips, he was President of Burlington Resources Canada from September 2004 to March 2006. From 1990 to 2004, Mr. Smolik worked in various engineering and asset management capacities for Burlington Resources Inc., including the Chief Engineering role from 2000 to 2004. He was a member of Burlington’s Executive Committee from 2001 to 2006. Mr. Smolik currently serves as a director of the American Exploration and Production Council. He previously served on the boards of directors of Cameron International Corporation and the Producers for American Crude Oil Exports. As the President and Chief Executive Officer of EP Energy, Mr. Smolik is the only officer of our company to sit on the board.

Clayton A. Carrell

Mr. Carrell has been our Executive Vice President and Chief Operating Officer since August 30, 2013 and Executive Vice President and Chief Operating Officer of EP Energy LLC since May 2012. He was previously Senior Vice President, Chief Engineer of our predecessor, EP Energy Corporation (a/k/a El Paso Exploration & Production Company) from June 2010 to May 2012. Mr. Carrell joined El Paso Corporation in March 2007 as Vice President, Texas Gulf Coast Division. Prior to that, he was Vice President, Engineering & Operations at Peoples Energy Production from February 2001 to March 2007. Prior to joining Peoples Energy Production, Mr. Carrell worked at Burlington Resources and ARCO Oil and Gas Company from May 1988 to February 2001 in various domestic and international engineering and management roles. He serves on the Industry Board of the Texas A&M Petroleum Engineering Department and is a member of the Society of Petroleum Engineers. Mr. Carrell is also a member of the Center for Hearing and Speech Board of Trustees.

Joan M. Gallagher

Ms. Gallagher has been our Senior Vice President, Human Resources and Administrative Services, since August 30, 2013 and Senior Vice President, Human Resources and Administrative Services, of EP Energy LLC since May 2012. She was previously Vice President, Human Resources of El Paso Corporation from March 2011 to May 2012. From August 2005 until February 2011, she served as Vice President, Human Resources of our predecessor, EP Energy Corporation (a/k/a El Paso Exploration & Production Company). In that capacity, Ms. Gallagher had HR responsibility for El Paso Corporation’s exploration and production business unit and from January 2010 to February 2011 she also had HR responsibilities for shared services and midstream. Prior to 2005, Ms. Gallagher served as Vice President and Chief Administrative Officer of Torch Energy Advisors Incorporated.

Dane E. Whitehead

Mr. Whitehead has been our Executive Vice President and Chief Financial Officer since August 30, 2013 and Executive Vice President and Chief Financial Officer of EP Energy LLC since May 2012. He was previously Senior Vice President of Strategy and Enterprise Business Development and a member of the Executive Committee of El Paso Corporation from October 2009 to May 2012. He previously served as Senior Vice President and Chief Financial Officer of our predecessor, EP Energy Corporation (a/k/a El Paso Exploration & Production Company), from May 2006 to October 2009. He was the Vice President and Controller of Burlington Resources Inc. from June 2005 to March 2006. From January 2002 to May 2005 he was Senior Vice President and Chief Financial Officer of Burlington Resources Canada. He was a member of the Burlington Resources Executive Committee from 2000 to 2006. From 1984 to 1993, Mr. Whitehead was an independent accountant with Coopers and Lybrand. He is a member of the American Institute of Certified Public Accountants.

Marguerite N. Woung-Chapman

Ms. Woung-Chapman has been our Senior Vice President, General Counsel and Corporate Secretary since August 30, 2013 and Senior Vice President, General Counsel and Corporate Secretary of EP Energy LLC since May 2012. She was previously Vice President, Legal Shared Services, Corporate Secretary and Chief Governance Officer of El Paso Corporation from November 2009 to May 2012. Ms. Woung-Chapman was Vice President, Chief Governance Officer and Corporate Secretary at El Paso Corporation from May 2007 to November 2009 and from May 2006 to May 2007 served as General Counsel and Vice President of Rates and Regulatory Affairs for El Paso Corporation’s Eastern Pipeline Group. She served as General Counsel of El Paso Corporation’s Eastern Pipeline Group from April 2004 to May 2006. Ms. Woung-Chapman served as Vice President and Associate General Counsel of El Paso Merchant Energy from July 2003 to April 2004. Prior to that time, she held various legal positions with El Paso Corporation and Tenneco Energy starting in 1991. Ms. Woung-Chapman is currently Vice-Chair of the Board of Directors for the Girl Scouts of San Jacinto Council.

Available Information

Our website is http://www.epenergy.com. We make available, free of charge on or through our website, our annual, quarterly and current reports, and any amendments to those reports, as soon as is reasonably possible after these reports are filed with the Securities and Exchange Commission (SEC). Information about each of our Board members, each of our Board’s standing committee charters, and our Corporate Governance Guidelines as well as a copy of our Code of Conduct are also available, free of charge, through our website. Information contained on our website is not part of this report.