2016 Oil & Gas Survival Guide

Transcription

1 Title: Oil & Gas Headline: Waiting on Keystone XL: Assessing the Potential Upside/ Downside for Canadian Oil Producers January 31, 2016 Oil & Gas 2016 Oil & Gas Survival Guide The NBF Daily Bulletin Industry Comment Industry Rating (Oil & Gas Exploration and Production): Market Weight (NBF Economics & Strategy Group) Brian Milne: (403) Dan Payne, CFA: (403) Kyle Preston, CFA, CMA: (403) In a world of commodity over-supply to begin the year, and with re-balancing likely to begin on both crude and gas through the back half of the year, we remain cautious for first half of 2016, but are more constructive towards the prospects for a meaningful rally in the second half of the year. Given pricing stress is expected to prevail through at least the medium term, and respective operating profiles are not generally sustained at current pricing (as discussed within this note), we continue to direct towards those producers with the most defensive characteristics (limited capital/dividend commitments, low costs & strong balance sheets). That said, we continue to note a group of operators whose business fundamentals remain reasonable and whose stock prices and valuations have underperformed, which could present attractive risk/reward exposure to a recovery. As such, we note defensive producer top picks as AAV, ARX, PEY, RRX, TOU, TVE, WCP and VET, relative to best positioned torquey top picks of BIR, BNE, CNQ, CPG, CJ and SPE. Macro Outlook; Over-Supplied with Re-Balancing Likely to Begin in H Crude Oil Suffice it to say, challenges abound for crude oil entering 2016, having sustained a ~2.0 mmbbl/d over-supply through 2015 resulting in a massive global inventory glut (~3.0 bln bbls) and significant price stress (down ~35% Y/Y, US$33/bbl WTI). Looking forward, we continue to await a rebalancing of the market to support a normalized pricing environment, with an emphasis of a rationalization on two-fronts: 1) S/D Imbalance, and 2) Global Inventories. First, assessing global supply/demand (S/D) fundamentals, we expect to see the beginnings of a rebalancing starting in 2016, with a forecast average imbalance of approximately +1.1 mmbbl/d (down from 1.8 mmbbl/d 2015), and the majority of progress expected in the second half of the year with the imbalance falling to +0.5 mmbbl/d, and reducing further to +0.1 mmbbl/d in Notable drivers include: A) Higher global demand forecast, up +1.3 mmbbl/d Y/Y (+1.4%), as driven by increased consumption in China (+0.3 mmbbl/d, +2.8% Y/Y), India (+0.2 mmbbl/d, +4.3% Y/Y) and the United States (+0.2 mmbbl/d, +0.6% Y/Y). We note potential risk from Chinese demand growth associated with a GDP growth forecast of +6.8% (vs. +6.4% in 2015), which could be at risk with any further slowing of its economy, and may stem contagion towards reduced global demand growth, specifically in emerging markets (forecast of +0.6 mmbbl/d, +2% Y/Y). B) Supply reduction seen from non-opec sources, with production forecast to fall approximately -0.1 mmbbl/d or -0.6% Y/Y (vs growth of +6.5 mmbbl/d, +11% Y/Y), and almost the sole contributor to declines projected to be the United States (-0.4 mmbbl/d, -2.5% Y/Y). Conversely, we continue to witness OPEC produce at very strong levels (32.9 mmbbl/d, +6.1% Y/Y), with Iranian volumes likely to further contribute to this robust supply in 2016/2017. With the bulk of forecast declines residing in the Americas, we note that there is potential to surprise to the downside, with our internally forecast assumptions projecting up to a 1.1 mmbbl/d decline by year end, which would contribute to significant rebalancing over that forecast (i.e., an incremental ~0.5 mmbbl on average, with more significant impact to 2017).

2 Page 2 Exhibit 1: World Supply vs. Demand World Supply vs. Demand (Annual & Quarterly) World Supply/Demand (mmbbl) S 120 US OPEC Other US China India EM Other S/D Imbalance S D S S S D D D Supply - Demand (mmbbl) World Supply/Damend (mmbbl) US OPEC Other US China India EM Other S/D Imbalance S S S S S S S S S S S D D D D D D D D D D D D Supply Demand (mmbbl) Source: NBF, EIA, OPEC Second, while supply/demand appears to be rebalancing, we continue to sit with historic highs in inventory (~3.0 bln bbls), and for which there is no near-term line of sight to a rationalization, given a forecast +1.1 mmbbl/d and +0.1 mmbbl/d supply/demand imbalance in 2016 and 2017, respectively. That is, rationalization of crude and product stocks are projected out in to 2018 and beyond at this time, presenting the primary impediment to a material rebound in pricing in the near term. Exhibit 2: Global Crude & Product Inventories IEA - WORLD CRUDE OIL INVENTORIES Global Inventories IEA - TOTAL CRUDE & MAJOR PRODUCT INVENTORIES mmbbls mmbbls 3,000 4,500 2,900 4,400 4,300 2,800 4,200 2,700 4,100 2,600 2,500 5-yr Range 5-yr Avg ,000 3,900 3,800 5-yr Range 5-yr Avg Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct DOE - US CRUDE OIL INVENTORIES DOE- TOTAL CRUDE & MAJOR PRODUCT INVENTORIES mmbbls 500 mmbbls Jan Feb 5-yr Range 5-yr Avg Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan 5-yr Range 5-yr Avg Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Source: NBF, IEA (Monthly data points with a 90-day lag), DOE Taking the above into context, we believe that pricing will remain stressed through 2016 (specifically in the first half of the year), with a potential rally in the second half of the year associated with a supply/demand rebalancing towards near-term normal pricing in the US$40-50/bbl range, which should continue in to 2017 towards what we believe will be a new normal pricing level of US$50-60/bbl associated with a normalizing supply/demand and inventory environment. That all said, potential to outperform currently anemic price forecasts stand as: 1) U.S. declines, and 2) Geopolitical unrest, versus downside risks of: 1) Chinese economic stress, and 2) Continued supply growth (e.g., U.S.).

3 Page 3 Exhibit 3: Crude Oil Production Efficiency 5 Year Historical US Oil Production & 12-Month Rig Count and Rig Efficiency ,600 Monthly US Production Rig Count (TTM) Monthly US Production 9.5 Rig Efficiency (Production adds per rig) , ,200 Oil Production (mmbbls/d) Rig efficiencies continue to show improvement at 3.3 mmbbl/rig, however on the back of continued shrinking rig counts, implied production shows a decline of 1.1 mmbbl/d through Jan. '17 under the assumption of static rig count Rig Efficiency (mbbl/rig) US Production (mbbl/d) , Oil Rig Count 6.0 and efficiency *Assumed rig count of 510 rigs as of January 29, 2016 Source: Bloomberg, EIA Natural Gas Natural gas remains the less topical, yet a similarly-themed commodity relative to oil, with significant over-supply resulting from persistently robust production and relatively anemic demand (i.e., warm winter), leaving a storage glut ~600 Bcf (~20%) above last year and the five-year average. Looking forward, and given the primary seasonal demand window is fast closing, our visibility to rebalancing stands on the back of production declines and an improved weather dynamic heading in to the winter of The production complex in the Lower 48 remains robust (71 Bcf/d, ~+1% Y/Y) and, given the trailing 12-month rig count is off 60% (127 vs. 316), exemplifies the continued strength of the efficiency of natural gas production. However, with increasing funding shortfalls and liquidity concerns related to lower liquids pricing, we continue to maintain optimism that production declines could be a material theme to emerge through For perspective, at current efficiency and rig counts, we forecast up to 7.0 Bcf/d could come off the market by the beginning of next winter. However, potentially mitigating this catalyst may be continued expansion of takeaway capacity in the Marcellus and Utica regions. On the demand front, exclusive of weather-driven residential/commercial demand, the Energy Information Administration (EIA) forecasts an incremental 1.2 Bcf/d of consumption by industrial end users through 2017 (0.7 Bcf/d & 0.5 Bcf/d in 2016 and 2017, respectively), which in addition to increased export demand of 2.3 Bcf/d through 2017 by way of LNG and pipeline exports to Mexico (1.5 Bcf/d and 0.8 Bcf/d in 2016 and 2017, respectively), should serve to incrementally support supply/demand fundamentals and pricing. While we expect fundamentals and pricing could continue to languish (similar to oil) through the first three quarters of 2016, the net impact of production declines and increased demand, by way of industrial consumption and net exports, should serve to support a material rebalancing of the market and more robust pricing in the $3-4/mcf range next winter. Exhibit 4: Natural Gas Storage Analysis 2015 and 2016 Natural Gas Storage Scenario Analysis 4,250 4,250 3,750 3,750 Total Storage (bcf) 3,250 2,750 2,250 5 Yr Range Total Storage (bcf) 3,250 2,750 2,250 5 Yr Range 1, , , /16 Forecast 1, /17 Forecast 750 Apr May Jul Aug Sept Nov Dec Jan Mar 750 Apr May Jul Aug Sept Nov Dec Jan Mar Note: 5-yr average used for build/draw forecast Source: NBF, EIA, Bentek

4 Page 4 Exhibit 5: Natural Gas Production Efficiency 5 Year Historical US Natural Gas Production & 12-Month Rig Count and Rig Efficiency ,500 Monthly US Production (Bcf/d) Rig Count (TTM) 75.0 Rig Efficiency (Production adds per rig) 75.0 Monthly US Production (Bcf/d) ,000 US Gas Production (Bcf/d) Rig efficiencies continue to show improvement at 21.0 mmcfl/rig, however, on the back of continued Rig Efficiency (mmcf/rig) US Gas Production (Bcf/d) ,500 1,000 Total Rig Count 61.0 shrinking rig counts, implied production shows a decline of Bcf/d through Jan. '17 under the assumption of static rig count and efficiency *Assumed rig count of 510 rigs as of January 29, 2016 Source: Bloomberg, EIA Industry Themes: Continue to Screen for Defensive Business Fundamentals Given pricing stress is expected to prevail through at least the medium term, and respective operating profiles are not currently sustained at current pricing (as discussed within this note), we continue to direct towards those most sustainable producers with defensive characteristics (i.e., strong balance sheets, low costs, limited capital/dividend commitments). As detailed within the following two themes: 1) Breakeven Analysis and 2) Sustainability Analysis. Breakeven Analysis; Industry Cost Deflation Brings Some Relief With the persistent drop in commodity prices over the past year and a half, we have seen a substantial reduction in oil and gas drilling activity, which has resulted in significant cost deflation across the industry. Looking at our oil/liquids-weighted coverage universe in particular, we note a 33% Y/Y reduction in 2015 capex and 16% Y/Y reduction in 2015 cash costs, while forecasting a further 14% and 9% Y/Y drop in 2016 capex and cash costs, respectively. Exhibit 6: Oil/Liquids Peer Group Y/Y Capex & Cash Costs Comparison Oil/Liquids Peer Group Aggregate Capital Spending & Cash Cost Trend $35 Capex $/boe $40 $40 Cash Costs $/boe $50 $30 $35 $35 $45 Capex (C$Billions) $25 $20 $15 $10-33% -14% $30 $25 $20 $15 $10 (C$/boe) Cash Costs (C$Billions) $30 $25 $20 $15 $10-16% -9% $40 $35 $30 $25 $20 $15 $10 (C$/boe) $5 $5 $5 $ Above data compiled from: AEI, BNE, BTE, BXO, CJ, CNQ, COS, CPG, CVE, ERF, GXO, MEG, MQL, NBZ, PGF, POU, PWT, RE, RRX, SGY, SKX, SOG, SPE, SU, TOG, TVE, VET, VII, WCP, ZAR Source: NBF, Company Reports Taking into account the cost deflation we have seen to date, we further examine the cash cost profile (as illustrated in Exhibit 7) across our oil universe and note an average cash cost of Cdn$26/boe and total cash outflow of Cdn$44/boe including capex and dividends.

5 Page 5 Exhibit 7: Oil/Liquids-Weighted Peers Cash Outflows Oil/Liquids-Weighted 2016E Cash Costs & Outflows $90 $80 Cash Costs Maintenance Capex Growth Capex Cash Dividend (net of Drip) $70 $60 (C$/boe) $50 $40 $30 $20 $10 Source: NBF, Company Reports However, this is not necessarily a good proxy for determining a company s breakeven as it also depends on the quality of oil being produced and price received for that oil. This is especially true for companies with heavy oil and/or oil sands production where you also need to account for the heavy oil differential and blending costs (for bitumen). To get a true breakeven price, we take this analysis one step further and calculate the WTI oil price that is required in order to cover each respective company s cash costs, capex and dividends (if applicable). Based on this analysis below, we can note that our oil universe requires an average WTI price of US$25/bbl to cover all cash costs and an average WTI price of US$46/bbl to cover capex and dividends as well. On the extreme end of the scale, we note that Vermilion (VET) has the lowest breakeven oil prices (mainly due to its European gas contribution), while MEG Energy (MEG) has the highest breakeven oil price (due to its pure bitumen exposure and high interest costs). Other notably low cost operators include: BNE, CPG, RRX, TVE and WCP. Exhibit 8: Oil/Liquids-Weighted Peer Group Breakeven Analysis $ Breakeven Oil Price $100 $80 WTI (US$/bbl) $60 $40 $20 Cash Costs 2016 Maintenance Capex 2016 Growth Capex Dividend 2016 WTI Strip Current WTI All-in Breakeven (incl. hedges) *Represents companies that do not hedge production, or have no volume hedged for Base case excludes impact of hedging; assumes NYMEX gas price held constant at US$ 2.40/mmbtu Above data compiled from: AAV, ARX, BIR, BNP, BXE, CKE, CQE, CR, DEE, ECA, ERF, KEL, LXE, MQL, NVA, PEY, PMT, PNE, POU, PPY, RMP, SRX, TET, TOU, VII Source: NBF, Company Reports, Bloomberg

6 Page 6 We applied the same analysis to our gas-weighted coverage below, where we see a similar improvement in the cost structure with a 31% Y/Y reduction in 2015 capex and 10% Y/Y reduction in 2015 cash costs, while forecasting a further 26% and 7% Y/Y drop in 2016 capex and cash costs, respectively. Exhibit 9: Gas Peer Group Y/Y Capex & Cash Costs Comparison Gas Peer Group Aggregate Capital Spending & Cash Cost Trend $16 Capex $/mcfe $6.00 $9 Cash Costs $/mcfe $5.00 Capex (C$Billions) $14 $12 $10 $8 $6 $4 $2-31% -26% $5.00 $4.00 $3.00 $2.00 $1.00 (C$/mcfe) Cash Costs (C$Billions) $8 $7 $6 $5 $4 $3 $2 $1-10% -7% $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $ (C$/mcfe) Source: NBF, Company Reports Looking at the specific cash cost profile for the gas-weighted producers below, we note an average cash cost of Cdn$2.43/mcfe and total cash outflow of Cdn$4.90/mcfe including capex and dividends. Exhibit 10: Gas-Weighted Peers Cash Outflows Gas-Weighted 2016E Cash Costs & Outflows $7 Cash Costs Maintenance Capex Growth Capex Cash Dividend (net of Drip) $6 $5 C$/mcfe $4 $3 $2 $1 Source: NBF, Company Reports Again, this is not necessarily a good proxy for determining a company s breakeven as it also depends on the quality of gas and liquids being produced and the price received which may take into account regional differentials. When applying our breakeven analysis to the gas-weighted producers, we note that our gas universe requires an average NYMEX gas price of ~US$1.20/mcf to cover all cash costs and an average NYMEX gas price of ~US$3.60/mcf to cover capex and dividends as well. On the extreme ends of the scale, we note that RMP has the lowest breakeven oil prices (mainly due to it low cost structure and contribution from its oil and liquids production), while PMT has the highest breakeven gas price (due to its high interest cost). Other notably low cost operators include; AAV, ARX, BIR, PEY and TOU.

7 Page 7 Exhibit 11: Gas-Weighted Peer Group Breakeven Analysis 2016 Breakeven Gas Price $10 $9 NYMEX (US$/mmbtu) $8 $7 $6 $5 $4 $3 $2 $1 Cash Costs 2016 Maintenance Capex 2016 Growth Capex Dividend NYMEX Strip (US$/mmbtu) Current NYMEX All-in Breakeven (incl. hedges) *Represents companies that do not hedge production, or have no volume hedged for Base case excludes impact of hedging; assumes WTI oil price held constant at US$36/bbl Source: NBF, Company Reports, Bloomberg Sustainability Analysis; Continue to Monitor Cash Outflow vs. Balance Sheet Strength While spending more cash than you are bringing in is not a sustainable business model over the long term, there are circumstances where a company may choose to operate at a loss for one reason or another (e.g., the cost and reservoir risk of shutting in an oil sands project is relatively high). In these circumstances, it is also important to assess a company s balance sheet and their ability to fund a potential cash shortfall over a certain period of time. To determine a company s ability to sustain itself, we present our colour-coded sustainability matrix which plots each company s D/CF ratio versus its total payout ratio (Exhibit 12). The closer to the lower left quadrant (Green: Low D/CF and Low payout), the more sustainable a company is, and the closer to the top right quadrant (Red: High D/CF and High payout), the less sustainable a company is considered to be. The most sustainable operators based on our analysis include; AAV, ARX, CPG, GXO, PEY, RRX, SPE, TOU, TVE, VET and WCP. Generally speaking, we would classify the companies higher up in the matrix as being at greater risk of cutting their capex and/or dividend (if applicable). However, we expect most companies will make adjustments to their capital budgets and/or dividends in the weeks ahead to align their payout profile with the current commodity price environment.

8 Page 8 Exhibit 12: Sustainability Analysis 2016E D/CF (x) 10.0x 9.5x 9.0x 8.5x 8.0x 7.5x 7.0x 6.5x 6.0x 5.5x 5.0x 4.5x 4.0x 3.5x 3.0x 2.5x 2.0x 1.5x 1.0x 0.5x 0.0x Avg 2016 D/CF = 4.4x PGF PNE PWT 2016e Leverage & Payout Sustainability Analysis Avg 2016 Net Payout Ratio = 139% BTE ZAR POU BXE TET ECA CNQ AEI BNP BNE ERF BXO MQL BIR RE NBZ TOG SGY CR CQE VET DEE KEL WCP SPE NVA CPG VII SU CJ PEY RMP AAV TVE CVE TOU SRX GXO ARX RRX SKX COS PPY PMT LXE MEG CKE SOG 0% 25% 50% 75% 100% 125% 150% 175% 200% 225% 250% 275% 300% 2016E Net Payout Ratio (%) Note: 2016e D/CF capped at 10.0x (COS, LXE, MEG, PMT, POU, PWT, SOG, ZAR); 2016e payout capped at 300% (CKE, LXE, MEG, PMT, SOG, TOO) and reflects Jan 6, 2016 strip pricing: US$39/bbl WTI, US$2.50/mmbtu NYMEX,.7100 CAD/USD; averages exclude nmf data Source: NBF, Company Reports, Bloomberg TOO RED = HIGH RISK OF FURTHER DIVIDEND/CAPEX ADJUSTMENTS OR OTHER ALTERNATIVE FUNDING (ie. DIVESTITURES) Expanding on the concept of sustainability, and focusing in on longevity, we assess the relative strength of producer s balance sheets with respect to credit capacity. In an environment with constrained reinvestment, shrinking reserves and falling price decks, excess credit capacity will be critical in order to defend assets and capitalization. The graph below depicts the defensibility of credit capacity, by way of relative leverage and production growth (as a proxy for PDP reserve lending value). That said, we continue to see lenders acting in a constructive manner towards those operators most actively taking a defensive stance against prevailing commodity price stress, and expect this theme to continue. Ultimately, regardless of value creation in the interim, a strong balance sheet subsequent to the prevailing stress will set the stage for long-term value creation potential. Exhibit 13: Credit Capacity Analysis 2016E D/CF 10.0x 9.0x 8.0x Credit Capacity Analysis Leverage vs. Production Growth PWT SOG MEG PMT ZAR AEI COS POU TOO ECA BXE BTE CNQ 7.0x ERF 6.0x BXO PGF SGY BNE MQL BNP RE 5.0x BIR WCP SPE SU CQE KEL CR PNE 4.0x TOG VET FRU NBZ RMP DEE VII PPY 3.0x CVE NVA CPG CJ PEY SRX 2.0x TVE RRX AAV GXO ARX TOU 1.0x SKX PSK LXE CKE BBI 0.0x -20% -10% 0% 10% 20% 30% 40% 50% 60% 70% 16/15 Production Growth (Q4/Q4) Note: 2016e D/CF capped at 10.0x (COS, MEG, PMT, POU, PWT, SOG, TOO, ZAR), 16/15 Production Growth capped at 70% (BBI, PNE, PPY, SRX) Source: NBF, Company Reports

9 Page 9 New Royalty Framework Promotes and Rewards Efficiency The Alberta Royalty Review Advisory Panel released its report on Friday, leaving the existing oil sands royalty framework largely intact while outlining several broad-based recommendations for the modernization of the existing conventional royalty framework. Perhaps most importantly, the new framework aims to support the reality of a globally competitive industry, with a view to rewarding the most efficient production of resources. As such, we expect that the most efficient Alberta weighted producers could be poised to benefit the most from the recommendations, while being less beneficial and possibly punitive to inefficient, high cost producers and those companies with significant Alberta freehold land exposure. Please see our full report, titled New Royalty Framework Promotes and Rewards Efficiency, for more details. Benefit of Better than Average Capital Efficiencies: As outlined in our royalty report, the government will look to transition from drilling credits towards a harmonized Drilling and Completion Cost Allowance, in order to foster a more equitable split of the Value Share (defined as revenue minus cost), and reward a more efficient industry incentivized by a beat the average mentality. To do this, the panel recommends that a cost allowance function be created, to represent the province s average well costs (as defined by depth and capital cost allocation) and support the thresholds for the pre & post-payout. For explanation sake, this may lead to an industry cost allowance for a well of $5 million of revenue before payout and escalating royalties commence. However, if a company is more capital efficient and comes in under industry averages stated by the cost allowance function, it will disproportionately benefit from the royalty holiday, which inherently improves economics. Low Cost Structure Prevails: For academic purposes, assuming comparable well production, realized pricing and cost allowance under the new royalty formula, two operators with varying capital and cost structures will still arrive at payout of the drilling cost allowance and migration towards the higher price-dictated rates at the same time. Why? Because payout is based on the revenue stream, not profitability. With that said, the more efficient operator should inherently strip more returns and margin from the revenue stream, ultimately enhancing project economics as compared with the less efficient operator. Based on the aforementioned comments, we believe companies posting better than average capital efficiencies and operating costs are in the best positon to benefit from the new royalty regime on a relative basis. Such companies include AAV, PEY and TOU in the gas space; and BNE, TVE, VII and WCP in the oil/liquids space. Exhibit 14: Gas-Weighted Capital Efficiency and Cash Flow Margin Comparison $30,000 $25, e Capital Efficiency vs. Cash Flow Margin (Gas Weighted) TET 2016e Capital Efficiency ($/boe/d) $20,000 $15,000 $10,000 $5,000 PMT CKE ECA ERF CQE KEL POU BBI PNE BXE NVA CR DEE ARX BNP PPY SRX RMP BIR TOU LXE AAV PEY 0% 10% 20% 30% 40% 50% 2016e Cash Flow Margin (excluding hedging) Based on strip pricing as of January 25, 2016 *Excludes hedging; Red or green dots represent those companies with greater than 40% of revenues coming from AB (NBF estimates) Source: NBF, Company reports 60% 70% 80%

10 Page 10 Exhibit 15: Liquids-Weighted Capital Efficiency and Cash Flow Margin Comparison $45,000 $40,000 SOG 2016e Capital Efficiency vs. Cash Flow Margin (Liquids Weighted) NBZ 2016e Capital Efficiency ($/boe/d) $35,000 $30,000 $25,000 $20,000 $15,000 PWT PGF ZAR TOO RE AEI MQL BTE CJ SPE VET SGY SKX GXO TOG WCP CPG VII TVE BXO BNE RRX $10,000 0% 10% 20% 30% 40% 50% 2016e Cash Flow Margin (excluding hedging) Based on strip pricing as of January 25, 2016 *Excludes hedging; Red or green dots represent those companies with greater than 40% of revenues coming from AB (NBF estimates) Source: NBF, Company reports M&A Outlook Financial stress and some recent transactions would lead one to believe that a ramp-up of M&A activity is possible in the near term. However, we maintain a more muted tone towards this theme, believing that the current environment poses a number of challenges towards consummating transactions, and being limited to select strategic transactions by a small group of well capitalized buyers. Factors that seem to be shaping the current M&A landscape are as follows: A) Few prospective buyers have a currency with which to transact: Broadly speaking, few parties have the relative financial flexibility and cost of capital to transact, and the market has a general bias against debt-financed deals; B) Market uncertainties are driving wide bid-ask spreads: Lack of visibility on commodity prices and a depressed forward curve, in addition to uncertainty surrounding such quantitative factors as upcoming reserve reports. Given a Challenged Landscape, what deals are possible? Our analysis suggests that a select number of companies have the financial flexibility to transact in the current environment, while even that group of prospective buyers remain cautious towards M&A and are particularly focused on making sure there is a clear strategic or financial benefit to engaging in a deal (especially if the deal requires third-party funding). As such, in the context of today s environment, we see the following types of transactions unfolding: A) Synergistic asset deals, including royalty/fee lands and/or infrastructure value (high perceived value; higher multiples required): These prospects are likely to be smaller, bolt-on opportunities (as opposed to corporate takeovers) that should provide synergies to an existing core asset (i.e., an increased working interest, operatorship, control of infrastructure, a fixed cash flow stream). Generally speaking, because of the strategic nature of these assets, they are likely to result in higher transaction metrics, which will be reserved for a smaller basket of purchasers with premium valuations and/or strong balance sheets. Historical precedents would suggest that these opportunities are likely to garner an annualized cash flow multiple north of 5.5x. A recent example would be Raging River s (RRX) purchase of synergistic assets from Anegada (private), and infrastructure deals involving companies such as Whitecap (WCP). 60% 70%

11 Page 11 B) Highly accretive deals on underappreciated assets (low perceived value; wide multiple discounts): While fewer buyers have interest in these highly accretive deals, a small number of producers have a strong cost of capital to leverage high accretion to excite the Street towards this transaction-type (i.e., Cardinal Energy (CJ) & Pine Cliff Energy (PNE)). These deals do not necessarily require an obvious strategic element, and investors are more inclined to hold these equities in anticipation of share price appreciation on the back of improving financial dynamics (i.e., cash flow accretion, improving sustainability measures). Precedent examples (CJ purchasing assets at Mitsue) would have us believe that most of these transactions will take place in the range of an annualized cash flow multiple of 4-5x. Assessing the M&A Landscape: Identifying the Likely Buyers & Sellers Taking the above factors and transaction qualifications in to consideration, we depict the relevant opportunities on the M&A front in the below graph. Specifically, we assess financial flexibility and valuation as leading indicators of the potential motivation of a seller (balance sheet stress), the financial feasibility of a deal (financial flexibility to transact) and the potential impact/reward of a deal (level of deal accretion).the more relevant groups of equities that shake out of our analysis are as follows (see Exhibit 16 below for more detail): Likely acquirers (Green): In our view, the companies that are more likely to be acquisitive are those with financial flexibility, including; AAV, ARX, CJ, FRU, GXO, PEY, PSK, RRX, SRX and TOU. Likely to divest (Blue): Companies that we see as being the most likely to divest of assets are those with an above-average balance sheet stress, and also a discounted multiple to facilitate pro-forma deal accretion and improved sustainability measures, including; BNP, BXO and PGF. Potential takeout candidates (Yellow): As a result of having quality assets, healthy balance sheets, while trading at a low cash flow multiple, we believe some producers could be well-positioned as takeout candidates (attractive for synergies, cash flow accretion and deleveraging capabilities), including: RMP and SKX. Other operators, with above-average leverage and a premium multiple, will be challenged to transact from either side of the ledger to adequately improve relative complexion. Exhibit 16: Valuation vs. Financial Flexibility Assessing the M&A Outlook Valuation vs. Financial Flexibility 2016E EV/DACF 16.0x 14.0x 12.0x 10.0x 8.0x 6.0x 4.0x BBI, CKE, FRU, LXE, PSK, SPE RRX KEL SGY SU Higher Multiple and Cleaner B/S CVE Increases Likelihood of Acquisitions TOG at Accretive Metrics WCP VET ARX PNE PEY CR BNE GXO CJ AAV SRX VII TOU PPY BIR NVA RE CPG Lower Probability of Showing Accretion on Acquisitions or ERF Divestitures MQL TVE RMP NBZ BXO CQE PGF BNP Cleaner Balance Sheet and Low Multiple Makes DEE Acquisitions or Divestitures SKX Less Likely CNQ COS, MEG, PMT, PWT, SOG, TOO, ZAR Lower Likelihood of Acquiring Given Stress to B/S: Higher Multiple Makes it Difficult to Show Accretion on Divestitures to Improve on Financial Flexibility BTE ECA BXE AEI POU Higher Probability of Divesting Given Stress to B/S; Lower Multiple Increases the Likelihood of Divesting at Accretive Metrics 2.0x 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 7.0x 8.0x 9.0x 10.0x 11.0x Based on strip pricing as of January 25, 2016 Source: NBF, Company Reports 2016E D/CF

12 Page 12 What Will the Catalyst to a Converging Bid-Ask Spread Be? Given the precipitous fall in the commodity prices and depressed state of the forward curve, resulting cash flow multiples have expanded, challenging the ability to transact at historical and/or accretive levels. So what forces could lead to an increase in activity? A) Uptick or Stability in the Commodity: Is the recovery in oil going to be V-shaped? U-shaped? Or could it be shaped like a bathtub (prevailing thesis)? Regardless, an increasing oil price, or consensus on medium/long-term stability in pricing, would help to compress multiples to levels more palatable for potential buyers (relative to historical transaction multiples), in addition to justifying more supportable values for sellers. B) Hands Forced by Lenders: Companies may be forced to sell assets as a means of covering a loan, whereby lenders are putting less emphasis on transaction metrics and more on just getting proceeds through the door (albeit high risk lending scenarios). However, this avenue remains suspect, due to lender reticence to exacerbate the supply glut of assets and the associated bid/ask spread. Exhibit 17: Historical Valuation vs. WTI Oil Price EV/DACF Historical Transactions Metrics vs. WTI Price Average EV/DACF (x) 10.0x 9.0x 8.0x 7.0x 6.0x 5.0x 4.0x 3.0x 2.0x 1.0x 0.0x Oil Gas WTI Price $120 $100 $80 $60 $40 $20 WTI Oil Price (US$/bbl) Source: NBF, Company Reports, Bloomberg Takeaways and Top Picks Given pricing stress is expected to prevail through at least the medium term, and respective operating profiles are not generally sustained at current pricing (as discussed within this note), we continue to direct towards those producers with the most defensive characteristics (limited capital/dividend commitments, low costs & strong balance sheets). That said, we continue to note a group of operators whose business fundamentals remain reasonable and whose stock prices and valuations have underperformed, which could present attractive risk/reward exposure to a recovery. For perspective on those that are well positioned, we ranked our universe on a scorecard basis (as illustrated in Exhibit 18), including balance sheet strength and relative sustainability (including decline, capital efficiency and netback at strip), and assessed the relative strength of business fundamentals against price performance since the peak. This highlights the relevant opportunities, including: Defensive Names; AAV, ARX, PEY, RRX, TOU, TVE, VET and WCP Torquey Names: BNE, BIR CNQ, CJ, CPG, SPE and TOG

13 Page 13 Exhibit 18: Price Performance & Sustainability Scorecard Ranking (#) TBE AEI BTE POU BNP ERF BXE TET MQL RE CQE RMP KEL SGY Share Price Performance & Sustainability Average: -57.3% CR DEE NVA VII 15 BNE PPY WCP BIR TVE TOG CPG 10 PNE AAV VET TOU CJ SKX RRX 5 ARX SRX PEY 0-100% -80% -60% -40% -20% 0% 20% 40% Share Price Performance (%) *Sustaining Ratio = (Decline x Capital Efficiency)/(Unhedged Cash Flow Netback x 365) **Company scorecard values calculated as the sum of each company's relative rank of sustaining ratio and D/CF ***Share price performance calculated as of market close January 26, 2016 vs. November 2014 OPEC meeting Source: NBF, Company Reports SPE

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15 Page 15 ADDITIONAL COMPANY RELATED DISCLOSURES Disclosures for Dan Payne s Company Coverage Disclosures for Brian Milne s Company Coverage Disclosures for Greg Colman s Company Coverage Disclosures for Kyle Preston s Company Coverage BBI 2,3,4,5,6,7 AAV 6,7,10 AFN 2,3,4,5,6,7 ARX 2,3,4,5,6,7 BIR 6,7 AEI 2,3,4,5,6,7 AGT 2,3,4,5,7 BNP 2,3,4,5,6,7 BNE 6,7 BXO 6,7, BDI BTE 2,3,4,5,6,7 BXE 6,7 CQE 6,7 CET 6,7 CNQ 6,7 CJ 6,7 CR 6,7 CEU COS 6,7 CKE 6,7,10 DEE 6,7 CFW CPG 2,3,4,5,7 KEL 2,3,4,5,6,7 GXO CVL CVE 2,3,4,5,6,7,10 LRE 6,7 * MEI 2,3,4,5,6,7 DAN 6,7 ECA 2,3,4,5,6,7,10 LXE 6,7 POU 2,3,4,5,6,7 ESN 6,7 ERF 6,7 MQL 6,7 RMP 6,7 FRC FRU 2,3,4,5,6,7 NVA 2,3,4,5,6,7 SOG 6,7 HNL 2,3,4,5,6,7 MEG PMT 6,7 SPE 6,7 HWO NBZ 6,7 PNE 6,7 TBE 6,7 INP PEY PPY 6,7 TET LSI PGF 6,7 RE 2,3,4,5,6,7 VII 2,3,4,5,6,7 MTL PSK 2,3,4,5,6,7 RRX 2,3,4,5,6,7 WCP 2,3,4,5,6,7 NAL 2,3,4,5,6,7 PWT 14 ** SGY 2,3,4,5,6,7 ZAR PHX SU 6,7 SKX PSI VET 6,7,10 SRX 2,3,4,5,7 RME 6,7 TOG 2,3,4,5,6,7 SCL 6,7 TOO 6,7 SES 2,3,4,5,6,7 TOU 2,3,4,5,6,7 STB 2,3,4,5,6,7 TVE 2,3,4,5,6,7,10 SVY TCW 10 TDG VIC 6,7,10 XDC LEGEND FOR COMPANY RELATED DISCLOSURES: 2 National Bank Financial Inc. has acted as an underwriter with respect to this issuer within the past 12 months. 3 National Bank Financial Inc. has provided investment banking services for this issuer within the past 12 months. 4 National Bank Financial Inc. or an affiliate has managed or co-managed a public offering of securities with respect to this issuer within the past 12 months. 5 National Bank Financial Inc. or an affiliate has received compensation for investment banking services from this issuer within the past 12 months. 6 National Bank Financial Inc. or an affiliate has a non-investment banking services related relationship during the past 12 months. 7 The issuer is a client, or was a client, of National Bank Financial Inc. or an affiliate within the past 12 months. 8 National Bank Financial Inc. or its affiliates expects to receive or intends to seek compensation for investment banking services from this issuer in the next 3 months. 9 As of the end of the month immediately preceding the date of publication of this research report (or the end of the second most recent month if the publication date is less than 10 calendar days after the end of the most recent month), National Bank Financial Inc. or an affiliate beneficially own 1% or more of any class of common equity securities of this issuer. 10 National Bank Financial Inc. makes a market in the securities of this issuer, at the time of this report publication. 11 A partner, director, officer or research analyst involved in the preparation of this report has, during the preceding 12 months provided services to this issuer for remuneration other than normal course investment advisory or trade execution services. 12 A research analyst, associate or any other person (or a member of their household) directly involved in preparing this report has a financial interest in the securities of this issuer. 13 A partner, director, officer, employee or agent of National Bank Financial Inc., is an officer, director, employee of, or serves in any advisory capacity to the issuer. 14 A member of the Board of Directors of National Bank Financial Inc. is also a member of the Board of Directors or is an officer of this issuer. * National Bank Financial Inc is acting as financial advisor to Long Run in connection with the definitive arrangement agreement with a group of investors based in the People's Republic of China. ** Gillian H. Denham is a member of the Board of Directors or is an officer of this issuer.