Financially, U.S. upstream companies are entering the year with a more responsible mindset. Companies have reached a capital spending level in which

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1 Production, Mbbl/d Crude Oil Production Outlook CONTACT US John Best Managing Director James Bevan Editor United States Crude Oil Production to Continue Growth in 2018 Criterion expects U.S. crude oil production to reach a fourth quarter 2018 average of 11.1 Mmbbl/d, rising 1.3 Mmbbl/d from fourth quarter 2017 volumes Permian Basin production will increase between December 2017 and December 2018 by 875 Mbbl/d (+30%) to a year-end average of 3,746 Mbbl/d The Williston Basin, Eagle Ford Shale and Niobrara will contribute 493 Mbbl/d in production growth through 2018 Upstream companies are focusing on fiscal responsibility in 2018, with 64% forecasted to spend within cash flows this year, rising from just 26% of companies in 2017 At year-end 2017, U.S. crude oil production crested 10.0 MMbbl/d and has already risen another 0.44 MMbbl/d to a March 2018 average of 10.4 MMbbl/d. Criterion expects this upward trajectory to continue during 2018 with U.S. crude oil production hitting 11.1 MMboe/d in the fourth quarter of Over the next nine months, Criterion believes that many of the trends which were prevalent in 2017 will be mirrored during Development programs in the Permian Basin are already more extensive than the prior year, with 45 drilling rigs being added in the first quarter alone. In addition the growth out of the Permian Basin, incremental volumes will be added in the Eagle Ford Shale, DJ Basin and out of the Williston. Financially, U.S. upstream companies are entering the year with a more responsible mindset. Companies have reached a capital spending level in which they can continue to grow production while also operating within cash flow from operations due to drastic reductions in well costs, operational improvements, manufacturing level development programs and hedging positions. Large independents have also begun to utilize low-cost basins such as the Eagle Ford Shale and DJ Basin to generate cash flow for use in the high-growth Permian Basin. To bring these new volumes to market, a new wave of Permian Basin midstream developments is scheduled to enter service in late-2018 and This will relieve extensive capacity constraints in Texas, allowing producers to continue with their development programs. In 2018, Criterion is forecasting a base case for U.S. crude oil production of 10.6 MMbbl/d, with fourth quarter production rising to 11.1 MMbbl/d Crude Oil Production Growth by Basin January 2018 through December ,600 1,400 1,200 1, (200) 1, (41) Total Permian Eagle Ford Bakken Niobrara Anadarko Other 1

2 Table of Contents 2018 U.S. Crude Oil Production Forecast... Pages 3-4 Permian Basin: More Spending & Higher Production... Pages Capital Spending & the Pure-Play Approach... Pages 5-6 Scaled Development Programs in the Permian Basin... Pages 6-7 Future Potential of the Permian Basin Layer Cake... Page 7 Permian Basin Long Haul Pipeline Developments... Pages 8-10 The Eagle Ford Shale: Incremental Growth in Pages Production Growth & Takeaway Capacity... Page 12 Utilizing the Eagle Ford as a Cash Flow Generator... Page 13 Rising M&A Activity in the Eagle Ford... Pages The Williston Basin: Relieved Capacity Constraints Allow for Growth... Pages Bakken Price Differentials Improve w/ Infrastructure Additions... Page 15 Rising Capital Spending in the Williston... Page 16 Positive Well Results in the Williston... Page 16 Niobrara & DJ Basin: An Emerging Growth Region... Pages Current Development Programs in the Niobrara & DJ Basin... Pages Companies Eyeing Future Development in the Niobrara & DJ Basin... Pages Expectations in the Oklahoma SCOOP & STACK... Page Upstream Capital Spending & Cash Flow Focus... Pages Crude Oil Hedging Summary... Pages Appendix... Page 23 2

3 ude Oil Production, MMbbl/d Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18 Mar-18 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Nov-18 Production in MMbbl/d Crude Oil Production Outlook 2018 U.S. Crude Oil Production In 2018, Criterion expects the U.S. upstream sector to maintain the momentum achieved during the prior year, and we expect crude oil volumes to grow by 1.3 MMbbl/d to a fourth-quarter 2018 average of 11.1 Mmbbl/d. Rapid production growth will continue in the Permian Basin, with incremental volumes also being added in the Eagle Ford Shale, Williston Basin, and the DJ Basin. We believe production growth will be biased towards the upside due to how rapidly volumes increased in 2017 when the U.S. upstream industry added 1.2 Mmbbl/d. Over the first three months of 2018, volumes have already accelerated to a March 2018 average of 10.4 Mmbbl/d. After surpassing 10.0 Mmbbl/d in late-2017, Criterion believes U.S. crude production will reach a fourth quarter 2018 average of 11.1 Mbbl/d United States Crude Oil Production Forecast Base High Low After the U.S. rig count fell throughout the fourth quarter of 2017 to a year-end 2017 total of 929 drilling rigs, it has rebounded with 64 new rigs being added over the first three months of The rig growth primarily came out of the Permian Basin which added 45 rigs. This further solidifies what producers are intending to do in U.S. Crude Oil Production v. Rig Count Source: Criteiron Research CL Production U.S. Rig Count (Continued on page 4) In the United States, 64 rigs have been added in the first quarter of 2018, including 45 in the Permian Basin ,

4 Production, Mbbl/d Production, Mbbl/d Crude Oil Production Outlook 1,200 1, (200) (400) 2017 Crude Oil Production Growth by Basin January 2017 through December , (233) Total Permian Bakken Niobrara Eagle Ford Anadarko Other Much like during 2017, the Permian Basin will account for the majority of crude oil growth. Companies within the basin spent 2017 investing in infrastructure development in anticipation of future growth while securing contracts with oilfield service firms, sand providers and water handling companies to lower costs for scaled development programs. A significant amount of upstream companies such as EOG have already locked in service costs for 2018, allowing them to protect the cost of their planned capital programs from excessive increases with rising demand for oilfield service equipment. In addition to the expected growth in the Permian Basin, Criterion is tracking rising investments in the Williston Basin, Eagle Ford Shale and the Niobrara/DJ Basin. Combined, these three regions will add a cumulative 486 Mbbl/d between January 2018 and December Thanks to the Dakota Access Pipeline System which went online in 2017, price differentials in the Williston Basin have drastically fallen, resulting in a renewed focus on development spending and Criterion is forecasting that the region will reach record crude oil production levels during Meanwhile, Eagle Ford companies have a mixed mentality for 2018, which we forecast will drive production up by 215 Mbbl/d in Meanwhile, the Niobrara & DJ Basin are showing signs of future growth potential in late-2018 and beyond. (Continued on page 5) 2018 Crude Oil Production Growth by Basin January 2018 through December ,600 1,400 1,200 1, (200) 1, (41) Total Permian Eagle Ford Bakken Niobrara Anadarko Other 4

5 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Nov-18 Crude Oil Production, Mmbbl/d Permian Basin Rig Count Crude Oil Production Outlook Permian Basin More Spending & Higher Production For the foreseeable future, the Permian Basin will serve as the United States primary growth driver for crude oil production. Operational efficiency improvements, manufacturing level development programs, massive midstream buildout and the discovery of new productive layers in the Permian will allow upstream companies to extract crude oil for years to come. Permian focused producers spent much of 2017 preparing to ramp-up development through new infrastructure additions and the implementation of cost-cutting efforts for scalable drilling programs. Between December 2017 and December 2018, Criterion forecasts that Permian Basin production will increase by 875 Mbbl/d (+30%) to a year-end average of 3,746 Mbbl/d. Permian Basin production will increase by 875 Mbbl/d (+30%) between Dec-17 and Dec Permian Basin Crude Oil Production v Rig Count Historical Forecast Rig Count Capital Spending and the Pure-Play Approach To drive further production growth in 2018, Permian Basin focused companies have boosted their capital spending plans in the basin by 28%. Among our sample set of 32 Permian Basin companies, we are forecasting $26.3 billion in planned capital spending dedicated explicitly to the Permian. Large independents such as Occidental Petroleum are doubling down on the basin, with projected capital spending in the Permian doubling from what they spent in Occidental was able to boost spending thanks to low development cost across a bulk of their acreage in the Permian. As of the fourth quarter of 2017, Oxy held 3,152 horizontal drilling locations with a breakeven below $50/bbl, giving Oxy 17 years of inventory to develop while running a ten rig program. EOG Resources, one of the Permian's most prominent developers, will be spending $1.7 billion on the Basin during 2018, rising 54% from 2017 spending of $1.1 billion. EOG stated that they could deliver on their 2018 spending plan with $50/bbl oil prices and generate significant cash flows with oil at $60/bbl. In addition to shifting further capital into the Permian Basin, several companies have begun to sell-off their acreage located outside of the Permian Basin in order to fund more extensive development programs. This allows companies to raise immediate capital from asset sales and it effectively transitions them into pure-play Permian Basin operators. The most notable transition has come from Pioneer Resources. In February 2018, Pioneer reported that (Continued on page 6) 5

6 they intend to divest their South Texas Eagle Ford, Raton and West Panhandle assets. The asset sales will be used to fund a 20-rig development program during 2018 and Pioneer expects to be cash flow breakeven at $58/bbl crude oil prices with a $2.65 billion drilling & completion capital program. Proforma the asset sales, Pioneer will be increasing their crude oil production by an estimated 19%-24% during Company Spending in the Permian Basin ($MM) Company Name Y/Y Increase Pioneer Natural Resources Co. $2,350 $2,650 13% Occidental Petroleum Corporation $1,200 $2, % Apache Corporation $1,953 $2,170 11% Concho Resources, Inc. $1,700 $2,000 18% EOG Resources, Inc. $1,100 $1,690 54% Parsley Energy, Inc. $1,075 $1,450 35% Diamondback Energy, Inc. $795 $1,400 76% Energen Corp. $875 $1,200 37% SM Energy Company $700 $1,032 47% Anadarko Petroleum Corporation $820 $1,000 22% Cimarex Energy Co. $732 $945 29% Noble Energy, Inc. $635 $941 48% RSP Permian, Inc. $663 $855 29% Encana $813 $775-5% Devon Energy Corporation $650 $725 12% QEP Resources, Inc. $550 $699 27% Laredo Petroleum, Inc. $630 $555-12% Matador Resources Company $453 $550 22% WPX Energy, Inc. $575 $537-7% Callon Petroleum Company $404 $520 29% PDC Energy, Inc. $351 $400 14% Marathon Oil Corporation $300 $391 30% Resolute Energy Corporation $278 $380 37% Halcon Resources Corporation $300 $300 0% EP Energy Corporation $275 $188-32% Ring Energy, Inc. $120 $150 25% Earthstone Energy $81 $144 78% Oasis Petroleum Inc. $0 $ % Approach Resources, Inc. $48 $60 25% Contango Oil & Gas Company $58 $52-10% Murphy Oil Corporation $40 $20-50% Mid-Con Energy Partners, LP $8 $7-18% Total $ 20,530 $ 26,305 28% Similarly, QEP Resources Board of Directors has approved a plan to transition the company into a pure-play Permian Basin focused producer. This will be accomplished via the divestment of the Williston Basin and Uinta assets with data rooms opening in March/April 2018, followed by the marketing of Haynesville/ Cotton Valley assets in the second half of Proceeds from asset sales will then be used to fund Permian development until QEP becomes cash flow positive in Scaled Development Programs in the Permian Basin The scaled development approach to the Permian Basin was touched upon in the prior 2018 crude oil outlook and companies are beginning to enact these programs on a larger scale. One of the more striking examples of the efficiencies created by this economy-of-scale approach is Project Aventine in New Mexico. Project Aventine is an oilfield service hub which will support rigs per year with frac sand, drilling equipment, chemicals and more via a 240-acre complex in Eddy County, New Mexico. Occidental has arranged the project alongside Schlumberger to cut drilling & completion costs by $0.5-$0.75 million per well. Other companies participating in the Project include Unimin (sand provider), CIG Logistics (facility operator), Sooner Pipe (Oil Country Tubular Goods) and OxyChem (Hcl provider.) With industry-wide developments such as Project Aventine, oilfield service companies are working alongside Permian Basin operators to reach agreements that benefit both parties. For Example, EOG Resources reported that for 2018, they have locked in 60% of completed well costs. EOG's protected rates cover 85% of 2018 rigs, 80% of the tubular cost, 60% of completion spreads, self-sourcing of 25% of completed well costs (sand, chemicals, water, etc.) and other measures. (Continued on page 7) 6

7 In addition to reducing service costs, Permian Basin companies are looking into the M&A markets to consolidate contiguous acreage positions which allows them to utilize longer horizontals and reduce overall development costs. The largest example of this was Concho s $9.5 billion acquisition of RSP Permian. If the deal closes, the combined entity will be running the largest drilling program in the region with a pro forma rig count of 27 drilling rigs and production of 267 Mboe/d. Concho highlighted that this would lead to large increases in supply chain and logistical improvements due to the scale of their merged operations. The new entity will have 26,000 gross drilling locations across 642,000 acres, allowing for the realization of cost savings related to batch drilling operations and the optimization of well designs. Future Potential of the Permian Basin Layer Cake Over the last few years, the industry has classified the geology in the Permian Basin as a layer-cake of development potential. The layered structure of the Permian region has allowed producers to utilize technological advancements to further divide up the Spraberry, Wolfcamp and other segments into multiple benches, leading to a consistent increase in drilling inventories across the region. Pioneer highlighted this in a recent investor presentation, drawing focus to their 2018 appraisal program which will include ten wells targeting several new intervals. In the short-term, this will consist of delineating the Jo Mill, Middle Spraberry and Wolfcamp D horizons. Notably, a recent Wolfcamp D completion by Pioneer in Midland County exhibited a 24-hour initial production rate of 3.6 Mboe/d (72% oil). Private producers have also highlighted the growth potential of the Wolfcamp C interval. PT Petroleum reported that its recent Wolfcamp C focused well (Orange 6091C) produced 953 boe/d in the first 30 days, 942 boe/d in the first 60 days and 898 boe/d over the first 90 days. The well is located on PT's Trinity Project, which is a 63,769-acre contiguous position in the Midland Basin of Reagan, Upton and Crockett Counties, Texas. PT Petroleum believes that the well "is likely not only to be Source: Pioneer Investor Presentation transformational for the Trinity Project, but for a large portion of the southern Midland Basin." The Orange 6091C well mentioned above was drilled at a lower landing position than wells drilled in the past, and PT has now mapped over 1,000-ft of gross Wolfcamp C interval across the entire Trinity Block, which could lead to potential two bench development. The upstream oil & gas industry has been underestimated in the past, and its important to keep that in mind moving ahead. Similarly, Percussion Petroleum reported that their four recent horizontal wells in Eddy County, New Mexico are producing at a record 30-day rate (IP30) out of the Yeso Formation in southeast New Mexico. Percussion's Goodman 22 4H well was drilled with a 4,835-ft lateral and is producing at an IP30 of 1,208 Mboe/d (80% oil). To date, Percussion has brought online four such wells at the cost of $3-$4 million per well with average IP30's of 1,080 boe/d per well (80% oil). The largest takeaway from the appraisal programs by Pioneer, PT Petroleum and others is that the Permian Basin as it stands today will rapidly change over time. The upstream oil & gas industry has been underestimated in the past, and it is essential to keep that in mind moving ahead. It is likely that further horizontal layers will be identified, exploited and made economic with the ever-advancing technological capabilities of upstream firms. Furthermore, the shale revolution in the Permian Basin will allow producers to adopt the same development programs across other high-cost U.S. resource plays in the future. (Continued on page 8) 7

8 Permian Basin Long Haul Pipeline Developments In response to production growth, midstream companies announced dozens of new projects to facilitate the flow of crude oil out of the Permian Basin. In Criterion's prior crude oil outlook, we were tracking 3,615 Mbbl/d in crude oil pipeline projects which would bring supply out of the Permian Basin and to markets along the Gulf Coast and in Oklahoma. Since that update, several new projects have been announced, pushing the total takeaway capacity being tracked to 4,270 Mbbl/d. This massive boost in capacity is largely scheduled for completion in 2019, which would line up with the completion of additional gathering infrastructure and terminals in the second half of Details on the current projects are as follows: Midland to Sealy Pipeline Phase 1 & 2 Enterprise s Midland to Sealy Pipeline is a 416-mile, 450 Mbbl/d crude oil pipeline running from the Enterprise Midland Terminal to its Sealy Storage facility in Houston, Texas. Phase 1 of the project went online at year-end 2017, adding 405 Mbbl/d in pipeline capacity with Phase 2 scheduled for completion in the second quarter of Enterprise expects volumes to ramp up through 2021, with 90% of committed volumes hitting the system in late The pipeline has an ultimate committed capacity of 405 Mbbl/d and a walk-up capacity of 45 Mbbl/d, bringing total system capacity to 450 Mbbl/d. Encana mentioned that it had firm capacity on the project in February Permian Basin Long-Haul Crude Oil Pipeline Projects Name Completion Date Project Status Volumes (Mbbl/d) Downstream Market (Continued on page 9) Pipeline Develoer Midland to Sealy Pipeline Phase 1 12/30/2017 Operational 405 Sealy. TX Enterprise Products Partners Permian Express 3 Pipeline - Phase 1 12/31/2017 Operational 100 Nederland, TX Permian Express Partners Midland to Sealy Pipeline Phase 2 4/30/2018 Under Construction 45 Sealy. TX Enterprise Products Partners Permian Basin Long-Haul Extension 9/30/2018 Under Construction 200 Cushing, Gulf Coast and More Plains All American Pipeline Oryx Delaware Basin Crude Oil Pipeline 12/31/2018 Under Construction 400 Crane & Midland, TX Oryx Midstream Services II EPIC Crude Pipeline 3/15/2019 Under Construction 590 Port of Corpus Christi Epic Pipeline LP BridgeTex Pipeline Expansion Phase 2 3/31/2019 Planned 40 Houston, TX BridgeTex Pipeline Company South Texas Gateway Crude Oil Pipeline 6/15/2019 Planned 400 Corpus Christi, TX Buckeye Partners Sunrise Loop Project (Phase II) 6/30/2019 Under Construction 120 Cushing, OK Plains All American Pipeline Cactus II Pipeline 9/30/2019 Under Construction 585 Corpus Christi, TX Plains All American Pipeline Gray Oak Pipeline 9/30/2019 Planned 385 Jupiter Pipeline 12/31/2019 Planned Permian & Eagle Ford to Gulf Coast Pipeline 12/31/2019 Planned 350 Corpus, Freeport and Houston, TX Three Rivers and Brownsville, TX Three Rivers, Corpus and Houston, TX Phillips 66, Enbridge Inc. JupiterMLP LLC Magellan Midstream Partners Permian to Gulf Coast Crude OIl Pipeline 3/31/2020 Planned 650 Houston, TX Enterprise Products Partners Total 4,270 8

9 Permian Basin Express 3 Phase 1 Energy Transfer Partners, through Permian Express Terminal LLC and Permian Express Partners LLC, announced that commenced an for the proposed Permian Basin Express 3 Pipeline on May 16, In its initial phase, the Permian Express 3 is carrying up to 100 Mbbl/d, and it entered service in the fourth quarter of Later expansions will provide for up to 300 Mbbl/d in transport capacity from the Delaware Basin, but no timeline has been issued. Permian Basin Long-Haul Extension In Early 2018, San Mateo Midstream entered into a strategic relationship with Plains All American in Eddy County, New Mexico. The agreement includes gathering and transport of crude oil through a Joint Tariff arrangement in a 400,000-acre joint development area. As part of the deal, Plains will construct a mainline extension of its regional long-haul system in Culberson County to a delivery point with San Mateo's crude oil system being built in Eddy County, NM. Construction will be completed in the second quarter or early third quarter of Oryx Delaware Bain Crude Oil Pipeline Oryx Midstream is building a new regional crude oil pipeline system in the Delaware Basin to carry 400 Mbbl/d in capacity. The pipeline is secured by a long-term agreement with WPX Energy and other regional producers with a dedication of 300,000 aces. The 220-mile pipeline is scheduled to enter commercial service by year-end 2018, and it will carry supply from around the Delaware Basin to Crane and Midland, Texas. EPIC Crude Oil Pipeline EPIC Pipeline, backed by Ares Capital, sanctioned the 650-mile EPIC Crude Oil Pipeline in January 2018 and it will parallel the planned EPIC NGL Pipeline which is also underway. The system will run from a receipt point in Orla, Texas to the Port of Corpus Christi and has a 590 Mbbl/d capacity. Terminals will be added in Orla, Pecos, Crane, Wink, Midland, Helena and Gardendale with a final delivery point at the Port of Corpus Christi. Commercial operation is currently set for Firm shippers include Noble Energy, who is dedicating its acreage in Reeves County, Texas and up to 75 Mbbl/d in crude oil production. An additional firm shipper was also secured in early 2018 with a 75 Mbbl/d commitment. Distinctive to the EPIC crude project, customers have been provided the opportunity to make commitments through volume or acreage dedications. BridgeTex Pipeline Expansion Phase 2 In early December, Magellan Midstream and Plains All American announced that their 50/50 owned BridgeTex Pipeline Company commenced a supplemental open season to secure commitments on the second expansion of their crude oil pipeline system. This new expansion will take the BridgeTex system's volumes from 400 Mbbl/d to 440 Mbbl/d in early The open season closed on December 30, BridgeTex, as it sits today, carries supply from Colorado City, Texas to Houston, Texas. (Continued on page 10) 9

10 South Texas Gateway Crude Oil Pipeline Buckeye Partners launched an open season on the newly proposed South Texas Gateway Pipeline in late- 2017, seeking shippers to fill 600 Mbbl/d in firm capacity on the project. The Gateway Pipeline, when built, will run from the Permian Basin and Gardendale, Texas to points in Corpus Christi, Ingleside and Houston, Texas. Further details have not yet been reported. Buckeye is also considering a crude oil pipeline header in Corpus Christi to link long-haul pipelines from the Permian to Corpus Christi destinations and refineries. Sunrise Loop Project (Phase II) Following the completion of a successful open season in mid-2017, Plains All American (PAA) decided to move forward with their 120 Mbbl/d Sunrise Extension Project (Phase I) and Sunrise Loop Project (Phase II) in July As part of the project, PAA will be extending the Sunrise Pipeline System, which currently flows from Midland to Colorado City, Texas, an additional 180-miles from Colorado City to Wichita Falls, Texas. The project is scheduled for completion in early to mid-2019, and it will deliver crude oil to PAA's terminal and other third-party terminals in Cushing, Oklahoma. Cactus II Pipeline In February 2018, PAA closed on the open season for their proposed Cactus II Pipeline, securing 525 Mbbl/d in firm capacity commitments on the project. Those commitments include 425 Mbbl/d in long-term minimum volumes commitments and 100 Mbbl/d associated with long-term acreage dedications. PAA reserved another 60 Mbbl/d for walk-up shippers on the system. Several shippers have options to acquire up to 35% of Cactus II by mid Permitting, ROW and procurement work is now underway with commercial operation in the third quarter of The project will include origin points in Orla, Wink South, Midland, Crane and McCamey, TX. The system could carry up to 570 Mbbl/d in capacity. Plains stated that the pipeline would include a combination of existing pipelines with two new pipelines, the first of which will run from Wink South to McCamey, TX and the second from McCamey to Corpus Christi. Gray Oak Pipeline On December 11, 2017, Phillips 66 and Enbridge launched an open season on the newly proposed Gray Oak Pipeline which will have an initial capacity of 385 Mbbl/d between West Texas and markets in Corpus Christi, Freeport and Houston, Texas. The project can expand beyond the initial capacity, depending on shipper interest and service is planned for the second quarter of Shippers will be able to select from origin stations in Reeves, Loving, Winkler and Crane Counties in West Texas. Jupiter Pipeline The Jupiter Pipeline is a development proposed by JupiterMLP, LLC, a private firm with operations in Texas that focuses on bringing supply from its terminals in the Permian to markets along the Gulf Coast. To further this goal, they are developing the 670-mile Jupiter Pipeline to carry an unstated quantity of crude oil from origin points in Orla, Texas to offtake points in Pecos, Three Rivers, Corpus Christi and then Brownsville. Additionally, JupiterMLP is developing a crude oil upgrading, processing and export terminal in Brownsville that will have 10 million barrels of storage, deep water dock access and the ability to process and upgrade high gravity crude oil. The projects currently have completion dates in late (Continued on page 11) 10

11 Crude Oil Production, Mmbbl/d Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Nov-18 Eagle Ford Basin Rig Count Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Crude Oil Production (Mmbbl/d) Rig Count Crude Oil Production Outlook The Eagle Ford Shale Incremental Production Growth in 2018 During the first nine months of 2017, crude oil production in the Eagle Ford Shale held under 1.20 MMbbl/d as producers pulled back on drilling programs. Production fell further in August 2017 as weather-related issues forced industry-wide shut-ins. After restoring a bulk of volumes that were shut-in, the Eagle Ford began to experience growth in October 2017, rising to nearly 1.25 MMbbl/d and closing out 2017 at 1.27 MMbbl/d Eagle Ford Crude Oil Production Historical Rig Count After restoring a bulk of volumes that had to be shut-in, the Eagle Ford began to experience growth in October After growing 0.11 MMbbl/d in the fourth quarter of 2017, Criterion is forecasting the Eagle Ford to continue its current growth trajectory during With moderate increases in the current rig count, the Eagle Ford is forecast to add another 0.21 MMbbl/d in crude oil production between January 2018 and December 2018, rising to a year-end 2018 production level of 1.48 MMbbl/d. This conclusion is grounded in several trends that have emerged across the region following the fourth quarter earnings season. Major upstream companies in the area are implementing one of three strategies in the Eagle Ford during 2018; 1) growing production, 2) holding production flat and generating cash flows, or 3) divesting acreage and placing it into the hand of companies looking to invest into drilling & completion programs. (Continued on page 12) Eagle Ford Crude Oil Production v Rig Count With moderate increases in the current rig count, the Eagle Ford is poised to add another 0.2 Mmbbl/d in crude oil production between February 2018 and Historical Forecast Rig Count December

12 Overall, capital spending in the Eagle Ford is forecast to be relatively flat during 2018, with a mixed mentality among operators in the basin Company Spending in the Eagle Ford Shale ($MM) Company Name Y/Y Increase EOG Resources, Inc. $900 $1,120 24% Chesapeake Energy Corporation $900 $750-17% Marathon Oil Corporation $620 $713 15% Sanchez Energy Corporation $537 $445-17% EP Energy Corporation $200 $313 56% Murphy Oil Corporation $316 $300-5% Noble Energy, Inc. $452 $294-35% Encana $250 $290 16% Devon Energy Corporation $175 $250 43% Baytex Energy $228 $193-15% SM Energy Company $175 $168-4% Earthstone Energy $23 $12-48% Amplify Energy $11 $5-55% Total $4,786 $4,852 1% Eagle Ford Production Growth & Growing Takeaway Capacity Among the 15 public upstream companies we are tracking in the Eagle Ford, a handful have plans to grow production during EOG Resources, who holds 582,000 net acres in the Eagle Ford, is aiming to ramp up its completion program in the basin with 260 net wells scheduled to come online during 2018, rising from the 217 completed in EOG s efforts in the Eagle Ford are part of 24% increase in capital spending in the region and is part of their overall goal of growing crude oil production 16-20% across their U.S. holdings in Meanwhile, EP Energy cited plans to boost Eagle Ford volumes substantially during 2018, marking their first significant increase since As of February 2018, EP s Eagle Ford crude oil volumes have risen 20% over fourth quarter 2017 production due to the acquisition of acreage from Carrizo and recent well results. To spur further growth, EP Energy is dedicating 50% of its 2018 capital budget to running a 1-2 drilling rig program in the region. Sanchez Energy, with a 285,000 net acre position in the Eagle Ford, issued a 5-year production guidance which equates to an 18% compound annual growth rate through This forecast would take Sanchez 2017 volumes of 70.3 Mboe/d to more than 105 Mboe/d by A bulk of this growth is forecast to occur in 2018 when Sanchez plans to ramp up volumes by 30%. Even though Sanchez intends to boost production through 2020, they cut 2018 capital spending by $100 million and are now shifting to the low-risk development of economic drilling locations. With EOG, EP Energy and Sanchez Energy all aiming to grow production in 2018, adding nearly 200 Mbbl/d in Eagle Ford crude oil production is not out of reach. Additionally, producers may be incentivized by growing export capabilities out of the Port of Corpus Christi nearby and several of the long-haul pipelines coming out of the Permian Basin over the next few years are being built to also run through the Eagle Ford Shale. (Continued on page 13) 12

13 Utilizing the Eagle Ford as a Cash Flow Generator Several major producers are investing into the Eagle Ford to maintain current production levels and generate cash flows for use in other core regions As mentioned in our prior crude oil outlook, the Eagle Ford shale is serving as a free cash flow generator for companies with a position in the Permian Basin, STACK play or other more profitable regions where growth is the goal. Devon, Marathon Oil, Noble and Murphy Oil have all expressed that they intend to hold their Eagle Ford production flat during 2018 while diverting cash flow generated in the region to other areas of interest. This operational mentality will allow a portion of Eagle Ford production to hold flat for the next few years while other producers such as EOG and EP Energy add incremental volumes. Noble Energy laid out its development plan in February 2018, which primarily focused on increasing volumes out of the Delaware Basin and moderately ramping up production in the DJ Basin. To fund those two growth regions, Noble stated that the Eagle Ford was going to be utilized to generate $370 million in free cash flow over that time span while production remained flat through Noble s U.S. Onshore Development Plan ( ) Source: Noble Investor Presentation Marathon Oil broke down its operational plans for its four core U.S. resource plays in 2018 as well. In the Eagle Ford, $710 million in capital spending will be used to maintain flat production and generate free cash flow for use in the Bakken, Oklahoma and the Delaware Basin. Similarly, Murphy Oil's 2018 capital spending guidance will include $300 million in Eagle Ford development spending. Murphy's budget will support the completion of 38 operated wells throughout the year and will allow Murphy to keep volumes flat. Rising M&A Activity in the Eagle Ford During the first half of 2018, M&A activity in the Eagle Ford has picked up significantly compared to Thus far, 14 deals have been announced valued at a total of $4.5 billion. In comparison, Criterion tracked 17 transactions through the entirety of 2017 with a value of $4.7 billion. Of the deals announced so far in 2018, $4.0 billion have been to private buyers, placing acreage in the hands of companies with capital to run development programs with an underlying goal of boosting production. Eagle Ford M&A Activity ( ) Source: Criterion M&A Database # of Deals Value ($B) $ $4.5 Criterion has tracked $4.5 billion in Eagle Ford related M&A transactions in 2018, which is nearly even with all deals recorded during 2017 (Continued on page 14) 13

14 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Nov-18 Crude Oil Production, Mmbbl/d Bakken Rig Count Crude Oil Production Outlook The most substantial move into the Eagle Ford was between TPG Pace Energy Holdings and Enervest. In March 2018, TPG announced that they would be acquiring Enervest s South Texas assets for $2.7 billion through a blend of cash and stock. As part of the deal, EnerVest and TPG are partnering to launch Magnolia Oil & Gas Corp., which will be led by TPG CEO Steve Chazen. The closing of the sale is expected in the second quarter of 2018, after which the new company will begin trading on the NYSE. Magnolia will hold 40 Mboe/d in Eagle Ford and Austin Chalk production on 360,000 total net acres in South Texas. The acreage includes 14,000 net acres in Karnes County and 345,000 net acres in the high-potential Giddings Field. Upon closing, EnerVest will receive $1.2 billion in cash and 120 million shares of common stock in the company. EnerVest will own 51% of Magnolia while TPG investors will hold 43% of the company. TPG s press release stated that they believe the combination of superior operating margins and attractive new well economics will allow Magnolia to deliver high-return, self-funded production growth and generate substantial free cash flow after drilling capital. The Williston Basin - Relieved Capacity Constraints Allow for Growth After the price collapsed in late-2014, the Williston Basin entered a period of declining production which saw crude volumes fall from a June 2015 high of 1.17 MMbbl/d to a December 2016 low of 0.96 MMbbl/d. Entering 2017, those losses were reversed and Williston Basin crude oil production rose 0.23 MMbbl/d, hitting a December 2017 average of 1.19 MMbl/d. The Williston was the second highest growth basin in the United States over that period, behind only the Permian Basin. An evolving midstream sector, improved price differentials and an overall increase in crude oil prices throughout the year allowed companies in the region to reinitiate drilling programs and begin adding new volumes. During 2018, Criterion expects the Williston Basin to cruise past the all-time high of 1.26 MMbbl/d which was set in Upstream companies will add approximately 0.14 MMbbl/d in 2018, rising to a December 2018 average of 1.33 MMbbl/d. (Continued on page 15) Bakken Crude Oil Production v Rig Count Historical Forecast Rig Count During 2018, Criterion expects the Williston Basin to cruise past the set in 2014, rising to a December average of 1.33 MMbbl/d

15 Bakken Price Differentials Improving with Added Infrastructure Over the last few years, pipeline capacity has served as the limiting factor for crude oil growth out of the Williston Basin of North Dakota. Rail transport was the initial solution to that problem, handling 72% of crude oil volumes out of the region during However, a widening North Dakota-WTI differential and the low price environment led to falling volumes. During 2017, the completion of the Dakota Access Pipeline changed the dynamics of the basin. As a result, pipeline transport now accounts for 76% of crude oil volumes brought out of the Williston Basin, allowing upstream companies to begin to realize higher prices for production. North Dakota Crude Oil Transport ( ) Pipeline 20% Local Refining 7% 2013 Truck 1% Local Refining 7% 2015 Truck 3% Rail 45% Local Refining 7% 2017 Truck 8% Rail 9% Rail 72% Source: North Dakota Pipeline Authority Pipeline 45% Pipeline 76% As a result of Dakota Access Pipeline and rising prices, Continental Resources saw a drastic change in its Bakken oil differential to WTI. Continental's differential improved from a 2016 average of $8.26/bbl to a fourth-quarter 2017 differential of $4.67/bbl. Oasis Petroleum & Whiting Petroleum reported similar results during the fourth quarter of 2017, with differentials of $0.50/bbl and $4.21/bbl, respectively. Continental is forecasting their Bakken oil differentials to remain low through 2018, with a recently revised transport contract lowering their differential on 30% of production to $3.75/bbl through Oasis also highlighted that there is ample capacity for Bakken crude oil production with the combination of pipeline capacity and rail options now available in the region. Oasis cited that total takeaway capacity as of 2017 is at 2.84 Mmbbl/d, far higher than Criterion s forecast December 2018 production of 1.33 MMbbl/d. (Continued on page 16) New crude oil pipeline capacity out of the Bakken has narrowed the price differentials in the basin, making development more economic Source: Continental Resources Investor Presentation 15

16 Rising Capital Spending in the Williston Basin With differentials steadily closing in the Williston, upstream companies have begun to reinvest into development programs. Criterion is tracking capital spending among ten companies with acreage in the region, and we are forecasting an 18% increase in Williston Basin capital spending during Hess will be boosting their Bakken expenditures 46% in 2018 to an average of $900 million to fund a six-rig program and to bring online 95 wells. Thanks to rising crude prices and low costs in the Williston, 61% of Hess future operated drilling inventory of 2,900 wells is economic at $50/bbl WTI prices. Notably, 24% of Hess inventory is profitable at $40/bbl WTI. Marathon Oil also broke down its operational plans for its four core U.S. resource plays in In the Bakken, MRO plans to deliver free cash flow alongside production growth with $598 million in planned spending. Company Spending in the Willston Basin ($MM) Company Name Y/Y Increase Continental Resources, Inc. $1,170 $1,250 7% Hess Corporation $616 $900 46% Marathon Oil Corporation $550 $598 9% Whiting Petroleum Corp. $518 $600 16% Oasis Petroleum Inc. $475 $715 51% WPX Energy, Inc. $250 $233-7% EOG Resources, Inc. $185 $100-46% Northern Oil and Gas, Inc. $130 $173 33% Denbury Resources Inc. $125 $150 20% Newfield Exploration Co. $73 $130 78% Total $4,092 $4,849 18% Positive Well Results in the Williston Basin During the fourth quarter of 2017, several companies in the Williston Basin highlighted very notable well results that indicate the future potential of the region. Marathon reported a 17% quarterly increase in crude oil production during the fourth quarter of 2017, bolstered by nine wells which were located in West Myrmidon and had average 30-day initial production (IP30) rate's of 2,935 boe/d, including one well which set a new Williston Basin IP30 record of 3,005 boe/d. Similarly, WPX Energy reported that its first two North Sunday Island wells drilled in the Williston Basin have each produced at 2,400 boe/d (81% oil) in their first 120 days of production. According to public data and internal records, WPX stated that these are the highest cumulative oil producing wells in a 90- and 120-day period in the history of the Williston Basin. These results are being mirrored across the Williston Basin, lending credence to Criterion s Williston Basin forecast for We expect volumes to hit a record level in the region by mid-2018, after which they will rise further to a December 2018 average of 1.33 MMbbl/d. (Continued on page 17) 16

17 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Nov-18 Crude Oil Production, Mmbbl/d Niobrara Basin Rig Count Crude Oil Production Outlook Niobrara & DJ Basin An Emerging Growth Region As we mentioned in the prior crude oil production outlook, the Niobrara & DJ Basin is an emerging growth region for U.S. crude oil and natural gas production. In January 2017, crude oil production in the Niobrara was averaging 0.40 MMbbl/d. Since then, it has risen to a March 2018 average of 0.58 MMbbl/ d, equating to a 45% increase and marking it as the third highest growth region in the United States. Looking into 2018, Criterion expects the region to grow by 0.13 MMbbl/d to a December 2018 average of 0.69 Mmbbl/d as producers continue to delineate acreage across the basin in anticipation of future development. The Niobrara & DJ Basin will contribute moderate growth in 2018 as Companies continue delineation programs ahead of full-field development Niobrara Crude Oil Production v Rig Count Historic Forecast Historic Several DJ Basin Focused Companies Planning to Grow Production in 2018 With spending across the entire oil & gas industry on the rise, upstream companies with acreage in the DJ Basin have raised their budgets by an average of 9%. Companies with core positions in the DJ Basin are planning to moderately increase production volumes while leveraging the region as a cash flow engine to fund development programs elsewhere, such as the Permian Basin. Anadarko, the largest operator in the region, is planning to invest $950 million into the DJ Basin during 2018, rising 13% from 2017 capital spending. The guidance comes after an impressive fourth quarter in which Anadarko boosted crude oil volumes in the DJ Basin by 20% quarter-on-quarter to more than 100 Mbbl/d. With the additional capital, Anadarko is projecting more than 30% year-on-year production growth from a five-rig, three completion crew program. Furthermore, Anadarko s April 2018 investor presentation mentioned that they had a $20/bbl breakeven cost in the basin and their new core type curve is projecting a before-tax rate of return above 100% on 300 planned well completions. Noble Energy, a holder of 321,800 acres in the DJ Basin, will be allocating $725 million to the region with a long-term goal of growing production at a compound annual growth rate of >15% through 2020 while generating $500 million in free cash flow over that period. Noble is utilizing cash flow out of the DJ Basin (coupled with Eagle Ford cash flows) to invest further into their primary growth engine, the Delaware Basin. Noble expects volumes to ramp up in their Wells Ranch and East Pony areas of the DJ Basin in late and through (Continued on page 18) 17

18 Company Spending in the Niobrara & DJ Basin ($MM) SRC Energy, who is purely focused on developing the DJ & Niobrara Basin, recently acquired 30,200 net acres and boosted their total holdings to 90,200 net acres. Through these acquisitions, SRC also added 600 gross drilling locations to exploit moving ahead. With new acreage in hand, SRC released a 2018 capital spending guidance of $510 million which will fund the completion of 116 (103 net) wells. Comparatively, SRC spent $461 million during 2017 on DJ Basin development. As a result, SRC s net daily production for 2018 is forecast to increase 47% annually to an average of 50 Mboe/d, and they have placed hedges on 30-50% of production to protect their expanded capital program. Other Companies Focused on Delineating Acreage, Future Development Possible EOG reported that during the fourth quarter of 2017, they continued to evaluate their 400,000 net acres position in the Powder River Basin. This included the completion of nine wells and testing of multiple target zones in the region. In the Powder River Basin, EOG has already identified the Turner Sand interval as a premium play, and they are testing 4,800-ft of stacked pay for further development potential. For 2018, EOG plans to complete 45 net wells in the region at the cost of $4.5 million per 8,000-ft lateral. In the DJ Basin, EOG completed three wells during the fourth quarter of 2017, highlighted by the Big Sandy H which had an IP30 of 1,110 boe/d. The DJ Basin Codell formation has already been identified as a premium play, and EOG plans to bring online 35 net wells in 2018 in the DJ Basin, more than double the 17 they brought online in Development Company Name Y/Y Increase Stage Anadarko Petroleum Corporation $840 $950 13% Full Field Noble Energy, Inc. $821 $725-12% Full Field Bill Barrett Corp.* $200 $ % Full Field PDC Energy, Inc. $457 $485 6% Full Field SRC Energy Inc. $460 $510 11% Full Field Whiting Petroleum Corp. $332 $75-77% Monetize Assets Chesapeake Energy Corporation $250 $275 10% Full Field EOG Resources, Inc. $230 $343 49% Delineation EP Energy Corporation $100 $125 25% Full Field SandRidge Energy $56 $80 43% Delineation Bonanza Creek Energy $125 $ % Full Field Newfield Exploration Co. $88 $130 48% Delineation Ultra Petroleum Corp. $575 $400-30% Delineation Vanguard Natural Resources $77 $114 48% Delineation Devon Energy Corporation $175 $150-14% Delineation Total $4,786 $5,212 9% *CapEx Rising Due to Merger with Fifth Creek Newfield also expressed that their Uinta Basin acreage, located west of the Niobrara DJ Basin, held 4,000-ft of stacked oil-saturated reservoir rock that could lend itself to future development. During 2017, Newfield ran a 20-well joint development program in the Central Basin area of their Rockies (Continued on page 19) 18

19 1/1/2017 3/1/2017 5/1/2017 7/1/2017 9/1/ /1/2017 1/1/2018 3/1/2018 5/1/2018 7/1/2018 9/1/ /1/2018 Crude Oil Production, Mmbbl/d Anadarko Basin Rig Count Crude Oil Production Outlook acreage, and they plan to continue a one-rig program throughout Newfield s 2018 capital program in the DJ Basin will include delineation work across multiple horizontal stacked horizons that Newfield believes may lead to future oil growth options. Due to multiple acreage holders in the Rockies still focusing on delineation or just now entering the development stage, Criterion expects the region to exhibit moderate growth during 2018 with higher upside potential looking into 2019 and beyond. To that end, we forecast the Niobrara to grow by 131 Mbbl/d in 2018 to a December 2018 average of 694 Mbbl/d Expectations in the Oklahoma SCOOP & STACK Crude oil production growth in the Anadarko basin during 2017 only accounted for 7% of growth across the entire United States, with volumes between January and December 2017 rising 71 Mbbl/d (+23%) to a December average of 485 Mbbl/d. Heading into 2018, Criterion believes that the SCOOP/STACK will continue growing at a similar rate, rising by 68 Mbbl/d to a December 2018 average of 553 Mbbl/d. Anadarko Basin Crude Oil Production v Rig Count The Oklahoma SCOOP & STACK formations are forecast to account for 5% of 2018 crude oil production growth; companies still delineating acreage Historic Forecast Rig Count Much like the Niobrara, producers in the oil-rich sections of the SCOOP & STACK are still delineating their assets ahead of full field development. Additionally, capital spending in the region among our tracked companies is forecast to rise 6% from what was invested during Looking ahead, many companies in Oklahoma have cited promising results out of the Meramec oil window. Newfield reported that they have recently turned-to-sales a 12-well spacing pilot, named Velta June, which targeted the Meramec formation from four well pads. The development consisted of 5,000-ft laterals with peak production surpassing 10,000 Boe/d from the entire project. Jones Energy also reported production results from a recent two-well Bone Pad which targeted the Meramec and Woodford formations. Jones Bone 2H well targeted the Meramec with a 4,375-ft lateral and had an IP24 of 1,878 boe/d (54% oil) and the lateral set a new company record for crude oil production per 1,000-ft of lateral in the Merge area. (Continued on page 20) 19